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Atlas Energy Resources, LLC – IPO: ‘S-1/A’ on 12/5/06

On:  Tuesday, 12/5/06, at 4:01pm ET   ·   Accession #:  1193125-6-246965   ·   File #:  333-136094

Previous ‘S-1’:  ‘S-1/A’ on 11/21/06   ·   Latest ‘S-1’:  This Filing

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

12/05/06  Atlas Energy Resources, LLC       S-1/A                  2:4.2M                                   RR Donnelley/FA

Initial Public Offering (IPO):  Pre-Effective Amendment to Registration Statement (General Form)   —   Form S-1
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: S-1/A       Amendement No. 4 to Form S-1 Registration           HTML   3.19M 
                          Statement                                              
 2: EX-23.1     Consent of Grant Thornton LLP                       HTML      6K 


S-1/A   —   Amendement No. 4 to Form S-1 Registration Statement
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Prospectus Summary
"Atlas Energy Resources
"Business Strategy
"Competitive Strengths
"Recent Developments
"Risk Factors
"The Transactions and Our LLC Structure
"The Offering
"Summary Historical and Pro Forma Financial Data
"Summary Reserve and Operating Data
"Non-GAAP Financial Measures
"Risks Inherent in Our Business
"Risks Inherent in an Investment in Us
"Tax Risks to Unitholders
"Cautionary Note Regarding Forward-Looking Statements
"Use of Proceeds
"Capitalization
"Dilution
"How We Make Cash Distributions
"Initial Quarterly Distribution
"Distributions of Available Cash
"Operating Surplus and Capital Surplus
"Distributions of Available Cash from Operating Surplus
"Management Incentive Interests
"Percentage Allocations of Available Cash from Operating Surplus
"Distributions from Capital Surplus
"Distributions of Cash Upon Liquidation
"Cash Distribution Policy and Restrictions on Distributions
"General
"Our Initial Quarterly Distribution Rate
"Financial Forecast
"Estimated Cash Available for Distribution
"Estimated EBITDA
"Sensitivity Analysis
"Unaudited Pro Forma Available Cash for Distributions
"Selected Historical Financial Data
"Management's Discussion and Analysis of Financial Condition and Results of Operations
"Comparability of Financial Statements
"Business Segments
"General Trends and Outlook
"Results of Operations
"Liquidity and Capital Resources
"Cash Flows
"Changes in Prices and Inflation
"Environmental Regulation
"Dividends
"Contractual Obligations and Commercial Commitments
"Critical Accounting Policies
"Recently Issued Financial Accounting Standards
"Quantitative and Qualitative Disclosures About Market Risk
"Business
"Overview
"Appalachian Basin Overview
"Gas and Oil Production
"Productive Wells
"Developed and Undeveloped Acreage
"Drilling Activity
"Investment Partnerships
"Tennessee Joint Venture Agreement
"Natural Gas and Oil Reserves
"Natural Gas Sales
"Crude Oil Sales
"Dismantlement, Restoration, Reclamation and Abandonment Costs
"Natural Gas Hedging
"Natural Gas Gathering
"Availability of Oil Field Services
"Major Customers
"Competition
"Markets
"Natural Gas and Oil Leases
"Seasonal Nature of Business
"Environmental Matters and Regulation
"Other Regulation of the Natural Gas and Oil Industry
"Litigation
"Management
"Our Board of Directors and Executive Officers
"Board Committees
"Governance Matters
"Compensation Committee Interlocks and Insider Participation
"Compensation of Directors
"Executive Compensation
"Employment Agreement
"Our Manager
"Officers of Our Manager
"Other Significant Employees
"Compensation of Our Manager's Directors
"Reimbursement of Expenses of Our Manager and its Affiliates
"Atlas Energy Resources Long-Term Incentive Plan
"Certain Relationships and Related Transactions
"Distributions and Payments to our Manager and Atlas America
"Agreements Governing the Transactions
"Conflicts of Interest and Fiduciary Duties
"Conflicts of Interest
"Fiduciary Duties
"Security Ownership of Principal Beneficial Owners and Management
"Description of the Common Units
"The Common Units
"Transfer Agent and Registrar
"Transfer of Common Units
"Our Limited Liability Company Agreement
"Organization
"Purpose
"Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney
"Capital Contributions
"Limited Liability
"Voting Rights
"Elimination of Special Voting Rights of Class A Units
"Issuance of Additional Securities
"Election of Members of Our Board of Directors
"Amendment of Our Limited Liability Company Agreement
"Merger, Sale or Other Disposition of Assets
"Termination and Dissolution
"Liquidation and Distribution of Proceeds
"Anti-Takeover Provisions
"Limited Call Right
"Meetings; Voting
"Non-Citizen Assignees; Redemption
"Indemnification
"Books and Reports
"Right To Inspect Our Books and Records
"Registration Rights
"Units Eligible for Future Sale
"Material Tax Consequences
"Partnership Status
"Unitholder Status
"Tax Consequences of Unit Ownership
"Tax Treatment of Operations
"Disposition of Common Units
"Uniformity of Common Units
"Tax-Exempt Organizations and Other Investors
"Administrative Matters
"State, Local and Other Tax Considerations
"Underwriting
"Legal Matters
"Engineers
"Experts
"Where You Can Find More Information
"Index to Financial Statements
"Introduction
"Unaudited Pro Forma Combined Balance Sheet as of September 30, 2006
"Unaudited Pro Forma Combined Statement of Income for the nine months ended September 30, 2006
"Unaudited Pro Forma Combined Statement of Income for the three months ended December 31, 2005
"Unaudited Pro Forma Combined Statement of Income for the year ended September 30, 2005
"Notes to Unaudited Pro Forma Combined Financial Statements
"Report of Independent Registered Public Accounting Firm
"Combined Balance Sheets as of September 30, 2004, 2005, December 31, 2005 and September 30, 2006
"Combined Statements of Income for the years ended September 30, 2003, 2004 and 2005 and three months ended December 31, 2004 and 2005 and nine months ended September 30, 2005 and 2006
"Combined Statements of Comprehensive Income for the years ended September 30, 2003, 2004, 2005 and the three months ended December 31, 2004 and 2005 and nine months ended September 30, 2005 and 2006
"Combined Statements of Combined Equity for the years ended September 30, 2003, 2004, 2005 and the three months ended December 31, 2005 and nine months ended September 30, 2006
"Combined Statements of Cash Flows for the year ended September 30, 2003, 2004, 2005 and three months ended December 31, 2004 and 2005 and the nine months ended September 30, 2005 and 2006
"Notes to Combined Financial Statements
"Balance Sheets as of July 14, 2006 and September 30, 2006
"Note to Balance Sheets
"Appendix A -- Form of Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC
"Appendix B -- Glossary of Terms
"Appendix C -- Reserve Report Summary

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  Amendement No. 4 to Form S-1 Registration Statement  
Table of Contents

As filed with the Securities and Exchange Commission on December 5, 2006

Registration No. 333-136094

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT

No. 4 to

FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

ATLAS ENERGY RESOURCES, LLC

(Exact name of registrant as specified in its charter)

 

Delaware

  1311   75-3218520

(State or other jurisdiction of incorporation or organization)

  (Primary Standard Industrial Classification Code Number)  

(I.R.S. Employer

Identification No.)

311 Rouser Road

Moon Township, Pennsylvania 15108

(412) 262-2830

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive office)

Edward E. Cohen

Atlas Energy Resources, LLC

311 Rouser Road

Moon Township, Pennsylvania 15108

(412) 262-2830

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Please send copies of communications to:

 

Lisa A. Ernst

  Thomas P. Mason

Mark E. Rosenstein

  Catherine S. Gallagher

Ledgewood

  Vinson & Elkins L.L.P.

1900 Market Street

  1001 Fannin Street

Philadelphia, Pennsylvania 19103

  Houston, Texas 77002

(215) 731-9450

  (713) 758-2222
 

Approximate date of commencement of proposed sale to the public: As soon as practicable after this registration statement becomes effective.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.  ¨

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell these securities and is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

 

PROSPECTUS   SUBJECT TO COMPLETION   December 5, 2006

6,325,000 Common Units

LOGO

ATLAS ENERGY RESOURCES, LLC

Representing Class B Limited Liability Company Interests

 


This is the initial public offering of our common units. No public market currently exists for our common units. We expect the initial public offering price to be between $19.00 and $21.00 per common unit.

Our common units have been approved for listing, subject to official notice of issuance, on the New York Stock Exchange under the symbol “ATN.”

Investing in our common units involves risks. Please read “ Risk factors” beginning on page 24.

These risks include:

 

Ø   We may not have sufficient cash flow from operations to pay our initial quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including payments to our manager.

 

Ø   If commodity prices decline significantly, our cash flow from operations may decline and we may have to lower our distribution or may not be able to pay distributions at all.

 

Ø   Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flows from operations and impair our ability to make distributions.

 

Ø   Our operations require substantial capital expenditures, which will reduce our cash available for distribution. We may not be able to obtain needed capital or financing on satisfactory terms.

 

Ø   Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships.

 

Ø   Our business depends on gathering and transportation facilities owned by Atlas Pipeline Partners, L.P. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

 

Ø   Atlas America, Inc. and its affiliates will own a controlling interest in us upon completion of this offering.

 

Ø   Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us.

 

Ø   Termination by us of our management agreement with our manager is difficult.

 

Ø   You will experience immediate and substantial dilution of $16.01 per common unit.

 

Ø   You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

 

      Per Common Unit    Total
Public offering price    $              $                     
Underwriting discounts and commissions(1)    $      $  
Proceeds, before expenses, to us    $      $  

(1)   Excludes structuring fee of $               payable to UBS Securities LLC in consideration of advice rendered by UBS Securities LLC related to the limited liability company structure of this offering and the related transactions described in the prospectus.

The underwriters may also purchase up to an additional 948,750 common units at the public offering price, less the underwriting discounts and commission payable by us, to cover over-allotments, if any, within 30 days from the date of this prospectus. If the underwriters exercise this option in full, the total underwriting discounts and commissions will be $                 and our total proceeds, before expenses will be $                      .

The underwriters are offering the common units as set forth under “Underwriting.” Delivery of the common units will be made on or about                 , 2006.

 

UBS Investment Bank   Wachovia Securities   A.G. Edwards

 

 

RBC Capital Markets   Friedman Billings Ramsey   KeyBanc Capital Markets
Credit Suisse   Sanders Morris Harris   Stifel Nicolaus

The date of this prospectus is             , 2006


Table of Contents

 

LOGO


Table of Contents

TABLE OF CONTENTS


 

PROSPECTUS SUMMARY

   1

Atlas Energy Resources

   1

Business Strategy

   5

Competitive Strengths

   6

Recent Developments

   6

Risk Factors

   6

The Transactions and Our LLC Structure

   6

The Offering

   9

Summary Historical and Pro Forma Financial Data

   16

Summary Reserve and Operating Data

   19

Non-GAAP Financial Measures

   21

RISK FACTORS

   24

Risks Inherent in Our Business

   24

Risks Inherent in an Investment in Us

   37

Tax Risks to Unitholders

   42

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

   45

USE OF PROCEEDS

   46

CAPITALIZATION

   47

DILUTION

   48

HOW WE MAKE CASH DISTRIBUTIONS

   50

Initial Quarterly Distribution

   50

Distributions of Available Cash

   50

Operating Surplus and Capital Surplus

   51

Distributions of Available Cash from Operating Surplus

   54

Management Incentive Interests

   54

Percentage Allocations of Available Cash from Operating Surplus

   57

Distributions from Capital Surplus

   57

Distributions of Cash Upon Liquidation

   58

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

   60

General

   60

Our Initial Quarterly Distribution Rate

   62

Financial Forecast

   63

Estimated Cash Available for Distribution

   64

Estimated EBITDA

   65

Sensitivity Analysis

   70

Unaudited Pro Forma Available Cash for Distributions

   71

SELECTED HISTORICAL FINANCIAL DATA

   74

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

   76

General

   76

Comparability of Financial Statements

   78

Business Segments

   78

General Trends and Outlook

   79

Results of Operations

   80

Liquidity and Capital Resources

   90

Cash Flows

   92

Changes in Prices and Inflation

   95

Environmental Regulation

   95

Dividends

   95

Contractual Obligations and Commercial Commitments

   96

Critical Accounting Policies

   96

Recently Issued Financial Accounting Standards

   98

Quantitative and Qualitative Disclosures About Market Risk

   100

BUSINESS

   103

Overview

   103

Recent Developments

   104

Business Strategy

   104

Competitive Strengths

   105

Appalachian Basin Overview

   107

Gas and Oil Production

   107

Productive Wells

   108

Developed and Undeveloped Acreage

   109

Drilling Activity

   110

Investment Partnerships

   110

Tennessee Joint Venture Agreement

   111

Natural Gas and Oil Reserves

   112

Natural Gas Sales

   114

Crude Oil Sales

   115

Dismantlement, Restoration, Reclamation and Abandonment Costs

   115

 


 

i


Table of Contents

 

Natural Gas Hedging

   115

Natural Gas Gathering

   116

Availability of Oil Field Services

   118

Major Customers

   118

Competition

   118

Markets

   119

Natural Gas and Oil Leases

   119

Seasonal Nature of Business

   120

Environmental Matters and Regulation

   120

Other Regulation of the Natural Gas and Oil Industry

   123

Litigation

   124

MANAGEMENT

   125

Our Board of Directors and Executive Officers

   125

Board Committees

   127

Governance Matters

   128

Compensation Committee Interlocks and Insider Participation

   129

Compensation of Directors

   129

Executive Compensation

   129

Employment Agreement

   129

Our Manager

   130

Officers of Our Manager

   131

Other Significant Employees

   132

Compensation of Our Manager’s Directors

   132

Reimbursement of Expenses of Our Manager and its Affiliates

   132

Atlas Energy Resources Long-Term Incentive Plan

   133

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   135

Distributions and Payments to our Manager and Atlas America

   135

Agreements Governing the Transactions

   136

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

   141

Conflicts of Interest

   141

Fiduciary Duties

   143

SECURITY OWNERSHIP OF PRINCIPAL BENEFICIAL OWNERS AND MANAGEMENT

   144

DESCRIPTION OF THE COMMON UNITS

   145

The Common Units

   145

Transfer Agent and Registrar

   145

Transfer of Common Units

   145

OUR LIMITED LIABILITY COMPANY AGREEMENT

   147

Organization

   147

Purpose

   147

Fiduciary Duties

   147

Agreement to be Bound by Limited Liability Company Agreement; Power of Attorney

   147

Capital Contributions

   148

Limited Liability

   148

Voting Rights

   148

Elimination of Special Voting Rights of Class A Units

   149

Issuance of Additional Securities

   149

Election of Members of Our Board of Directors

   150

Amendment of Our Limited Liability Company Agreement

   150

Merger, Sale or Other Disposition of Assets

   152

Termination and Dissolution

   152

Liquidation and Distribution of Proceeds

   152

Anti-Takeover Provisions

   153

Limited Call Right

   154

Meetings; Voting

   154

Non-Citizen Assignees; Redemption

   155

Indemnification

   155

Books and Reports

   156

Right To Inspect Our Books and Records

   156

Registration Rights

   157

UNITS ELIGIBLE FOR FUTURE SALE

   158

MATERIAL TAX CONSEQUENCES

   159

Partnership Status

   160

Unitholder Status

   161

Tax Consequences of Unit Ownership

   162

Tax Treatment of Operations

   167

Disposition of Common Units

   171

Uniformity of Common Units

   173

 


 

ii


Table of Contents

 

Tax-Exempt Organizations and Other Investors

   174

Administrative Matters

   175

State, Local and Other Tax Considerations

   177

UNDERWRITING

   178

LEGAL MATTERS

   183

ENGINEERS

   183

EXPERTS

   183

WHERE YOU CAN FIND MORE INFORMATION

   183

INDEX TO FINANCIAL STATEMENTS

   F-1

Appendix A – Form of Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC

   A-1

Appendix B – Glossary of Terms

   B-1

Appendix C – Reserve Report Summary

   C-1

 

You should rely only on the information contained in this prospectus. We have not, and the underwriters have not, authorized anyone to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, offering to sell our common units or seeking offers to buy our common units in any jurisdiction where offers and sales are not permitted. The information contained in this prospectus is accurate only as of the date on the front cover of this prospectus, regardless of the time of delivery of this prospectus or any sale of the common units offered hereby.

 


 

iii


Table of Contents

Prospectus summary

This summary highlights information contained elsewhere in this prospectus. You should read the entire prospectus carefully, including the historical and pro forma financial statements and the notes to those financial statements. The information presented in this prospectus assumes (1) an initial public offering price of $20.00 per common unit, the mid-point of the price range set forth on the front cover of this prospectus, and (2) that the underwriters do not exercise their option to purchase additional common units.

You should read “Risk factors” beginning on page 24 for information about important factors that you should consider carefully before buying our common units. We include a glossary of some of the industry terms used in this prospectus in Appendix B. Wright and Company, Inc., an independent engineering firm, provided the estimates of our proved natural gas and oil reserves as of March 31, 2006 included in this prospectus. A summary prepared by Wright and Company of its reserve report is located at the back of this prospectus as Appendix C, and is referred to in this prospectus as the reserve report. References in this prospectus to “Atlas Energy Resources,” “we,” “our,” “us,” or like terms, when used in an historical context or in the present tense, refer to the subsidiaries that Atlas America will contribute to Atlas Energy Resources in connection with this offering and, when used prospectively, refer to Atlas Energy Resources, LLC and its subsidiaries. References to fiscal 2005 are to Atlas America E&P Operations’ most recent fiscal year end, which was September 30, 2005. Atlas America E&P Operations changed its year end to December 31 and therefore audited financial statements are included in this prospectus as of and for the three months ended December 31, 2005. Our first fiscal year will end on December 31, 2006. References to “our manager” or “Atlas Energy Management” are to Atlas Energy Management, Inc.

ATLAS ENERGY RESOURCES

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in the Appalachian Basin. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage. Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business.

We were formed in June 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group, Inc. and in 1999 when it acquired Viking Resources Corporation, both engaged in the development and production of natural gas and oil and the sponsorship of investment partnerships.

We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America. Through our manager, the Atlas America personnel currently responsible for managing our assets and capital raising will continue to do so on our behalf upon completion of this offering.

As of September 30, 2006, our principal assets consisted of:

 

Ø   working interests in 6,415 gross producing gas and oil wells;

 

Ø   overriding royalty interests in 632 gross producing gas and oil wells;

 

Ø   our investment partnership business, which includes equity interests in 91 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

 

1


Table of Contents
Ø   approximately 568,900 gross (516,200 net) acres, primarily in the Appalachian Basin, over half of which, or approximately 308,300 gross (294,800 net) acres, are undeveloped; and

 

Ø   an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres in Tennessee.

In addition, at March 31, 2006, the date of our most recent reserve report, we had proved reserves of 170.9 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells.

For the twelve month period ended September 30, 2006, we produced 25,924 Mcfe/d which includes the proportionate share of production from our investment partnerships as well as our direct interests in producing wells. This resulted in an average proved reserves to production ratio, or average reserve life, of approximately 18 years based on our proved reserves at March 31, 2006.

According to Rigdata.com, we were the 11th most active operator in the United States based on well starts from January 2006 to October 2006. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

 

Ø   Gas and oil production.    We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

 

Ø   Partnership management.    As managing general partner of our investment partnerships, we receive the following fees:

 

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

 

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

 

  Ø   Well services.    Each partnership pays us a monthly per well operating fee, currently $100 to $457, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

  Ø  

Gathering.    Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing of this offering, pursuant to the

 

2


Table of Contents
 

terms of our contribution agreement with Atlas America, our gathering revenues and costs within our partnership management segment will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.” We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense.

The following table shows our revenues and segment margins and investment partnership and reserve data for the periods indicated.

 

    Years ended September 30,    

Three months

ended

December 31,

2005

   

Nine months

ended

September 30,

2006

 
    2002     2003     2004     2005      
  (unaudited)                             (unaudited)  

Segment results (in thousands):

           

Revenues:

           

Gas and oil production

  $ 28,916     $ 38,639     $ 48,526     $ 63,499     $ 24,086     $ 66,696  

Partnership management:

           

Well construction and completion

    55,736       52,879       86,880       134,338       42,145       135,329  

Administration and oversight

    4,805       5,090       8,396       9,590       2,964       8,487  

Well services

    7,585       7,635       8,430       9,552       2,561       9,498  

Gathering(1)

    3,497       3,898       4,191       4,359       1,407       6,902  
                                               

Total partnership management

    71,623       69,502       107,897       157,839       49,077       160,216  
                                               

Total revenues

    100,539       108,141       156,423       221,338       73,163       226,912  

Segment margin(2):

           

Gas and oil production

    20,652       30,153       39,688       54,429       21,628       54,190  

Partnership management:

           

Well construction and completion

    7,293       6,897       11,332       17,522       5,497       17,652  

Administration and oversight

    4,805       5,090       8,396       9,590       2,964       8,487  

Well services

    3,838       3,862       4,032       4,385       1,074       3,958  

Gathering(1)

    (7,307 )     (10,695 )     (13,051 )     (17,622 )     (6,561 )     (15,976 )
                                               

Total partnership management

    8,629       5,154       10,709       13,875       2,974       14,121  
                                               

Total segment margin(2)

    29,281       35,307       50,397       68,304       24,602       68,311  

Investment partnership and reserves data:

           

Funds raised (in millions)

  $ 41.1     $ 66.1     $ 107.7     $ 148.7     $ 52.2     $ 147.6  

Gross wells completed(3)

    252       296       505       662       192       505  

Developed acres:

           

Gross

    264,900       225,800       233,800       245,000       249,400       260,600  

Net

    194,100       188,200       197,200       206,700       210,600       221,400  

Undeveloped acres:

           

Gross

    222,900       205,400       249,800       267,300       271,500       308,300  

Net

    212,600       190,500       236,000       253,900       258,100       294,800  

Total acres:

           

Gross

    487,800       431,200       483,600       512,300       520,900       568,900  

Net

    406,700       378,700       433,200       460,600       468,700       516,200  

Total reserves managed (Bcfe) (end of period)

    317.1       332.2       365.2       401.1       403.1       397.5 (4)

Proved reserves, net to us (Bcfe) (end of period)

    134.5       144.4       155.8       171.6       171.5       170.9 (4)

% natural gas

    91.6 %     92.3 %     91.2 %     92.1 %     92.1 %     92.5 %(4)

% proved developed(5)

    70.7 %     68.3 %     69.6 %     68.5 %     70.8 %     70.2 %(4)

Production (Mmcfe/d)(6)

    22.3       21.7       22.9       23.5       24.1       26.6  

Reserves to production ratio (years)

    16.5 x     18.2 x     18.6 x     20.0 x     19.9 x     17.6 x(7)

(1)  

We charge gathering fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. We in turn pay these fees, plus an additional amount to bring the total gathering charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreement with it. Upon the completion of this offering, Atlas America will

 

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assume our obligation to pay gathering fees to Atlas Pipeline. We will be obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses within our partnership management segment will net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems. The expenses associated with these systems are shown as gathering fees on our combined statements of income. We will not own these gathering systems upon completion of this offering.

(2)   Please see “—Non-GAAP Financial Measures” for a definition of segment margin and a reconciliation of segment margin to our gross margin.
(3)   Wells in which we completed drilling during the periods indicated, regardless of when we initiated drilling. See “Business—Drilling activity.”
(4)   Amounts shown are as of March 31, 2006, not September 30, 2006, and are derived from our most recent reserve report.
(5)   The balance of our reserves are proved undeveloped. Our ownership in these reserves is subject to reduction as we generally contribute leasehold acreage associated with our proved undeveloped reserves to our investment partnerships in exchange for an approximate 30% equity interest in these partnerships, which effectively will reduce our ownership interest in these reserves from 100% to 30% as we make these contributions.
(6)   Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and (ii) our proportionate share of production from wells owned by the investment partnerships in which we have an interest, based on our equity interest in each such partnership and based on each partnership’s proportionate net revenue interest in these wells.
(7)   Based on annualized production for the nine months ended September 30, 2006 of 26.6 Mmcfe/d and our proved reserves at March 31, 2006.

Gas and oil production

As of September 30, 2006, we owned interests in 7,047 gross wells, principally in the Appalachian Basin, of which we operated 5,978. On average during the quarter ended September 30, 2006, gross production from our wells was approximately 85.9 Mmcfe/d, or approximately 12.2 Mcfe/d per well. In the three years ended September 30, 2006 we have drilled 1,864 gross (616 net) wells, 98% of which were successful in producing natural gas in commercial quantities, including 697 gross wells in the twelve months ended September 30, 2006, 99% of which were successful.

In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy, LLC that gives us an exclusive right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres owned by Knox Energy. As of September 30, 2006, we had drilled 114 net wells under this agreement. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

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 September 30, 2006, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.36 per MMBtu. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

Partnership management

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $199.8 million in the twelve months ended September 30, 2006 and $148.7 million in fiscal 2005. During the twelve months ended September 30, 2006 our investment partnerships invested $206.5 million in drilling and completing wells, of which we contributed $55.0 million. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

 

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We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues which are not directly dependent on natural gas and oil prices.

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

Natural gas hedging

We seek to provide greater stability in our cash flows through our use of financial hedges and physical hedges. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of November 1, 2006, we had financial hedges and physical hedges in place for approximately 77% of our expected production for the twelve months ending December 31, 2007.

Hess Corporation and other third-party marketers to which we sell gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us through physical hedge transactions. These transactions are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by these third-party marketers for volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value.

BUSINESS STRATEGY

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business. The key elements of our business strategy are:

 

Ø   Expand our gas and oil production through continued growth in our sponsorship of investment partnerships.

 

Ø   Expand our fee-based revenue through continued growth in our sponsorship of investment partnerships.

 

Ø   Expand operations through strategic acquisitions.

 

Ø   Expand the number of our drilling locations in the Appalachian Basin through an active leasing program and joint ventures.

 

Ø   Maintain control of operations.

 

Ø   Continue to manage our exposure to commodity price risk.

 

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COMPETITIVE STRENGTHS

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

 

Ø   Our partnership management business improves the economic rates of return associated with our gas and oil production activities.

 

Ø   Fee-based revenues from our investment partnerships provide a stable foundation for our distributions.

 

Ø   We are one of the leading sponsors of tax-advantaged investment partnerships.

 

Ø   We have a high quality, long-lived reserve base.

 

Ø   We have a significant inventory of future drilling locations and undeveloped acreage.

 

Ø   We have long-standing relationships with regional drilling contractors, service providers and equipment vendors.

 

Ø   Our relationship with Atlas Pipeline gives us reliable access to the markets we serve and reduces capital expenditures we would otherwise incur.

 

Ø   Through our manager, we have significant engineering, geologic and management experience in our core Appalachian Basin operating area.

RECENT DEVELOPMENTS

During the fourth quarter of 2006 and the first quarter of 2007, we and our investment partnerships plan to drill 3 wells to multiple pay zones, including the Marcellus Shale of Southwest Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet on our acreage in Fayette, Westmoreland and Greene Counties. We hold approximately 100,000 acres of prospective Marcellus acreage in these counties. Most of this acreage is held by production, meaning that it is covered by a continuing lease due to production from the property.

RISK FACTORS

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited liability company structure and the tax characteristics of our common units. Please carefully read “Risk factors” immediately following this section beginning on page 24.

THE TRANSACTIONS AND OUR LLC STRUCTURE

General.    We were formed in June 2006 as a Delaware limited liability company to own and operate the natural gas and oil assets and the investment partnership management business of Atlas America. Atlas America is a separate entity from us, and its securities are not being offered in this offering. Our operations will be conducted through, and our operating assets will be owned by, our operating subsidiaries, including Atlas Energy Operating Company, LLC. We will have no significant assets other than our interest in our subsidiaries.

Contribution of Assets by Atlas America.    At the closing of this offering, Atlas America will contribute to us its interests in its natural gas and oil development and production subsidiaries. Before the closing, some of these subsidiaries will distribute to Atlas America, and thus we will not acquire their interests in a small gathering system. We anticipate paying the net proceeds of this offering, after payment of offering expenses, to Atlas America as reimbursement of capital expenditures incurred by it on our behalf and partial consideration for its contribution of assets to us.

 

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Our Management.    We will enter into a management agreement with Atlas Energy Management pursuant to which it will be responsible for managing our day-to-day operations, subject to the supervision and direction of our board of directors. Our manager is a wholly-owned subsidiary of Atlas America. Neither we nor our manager will directly employ any of the persons responsible for our management or operations. Rather, personnel of Atlas America currently involved in managing our assets will manage and operate our business. Our manager will be entitled to distributions on our Class A units and management incentive interests. For more information about our management, please read “Management” and “Certain relationships and related transactions.”

Units Outstanding after this Offering.    After giving effect to this offering and the related formation transactions:

 

Ø   Atlas America will own 30,299,365 common units, representing approximately an 81.0% membership interest in us;

 

Ø   Richard D. Weber, our President, Chief Operating Officer and a director, will own approximately 50,000 common units, representing approximately a 0.1% membership interest in us;

 

Ø   Our manager will own 748,456 Class A units, representing an aggregate 2.0% membership interest in us, and all of the management incentive interests; and

 

Ø   the public unitholders will own 6,325,000 common units, representing approximately an aggregate 16.9% membership interest in us.

We will use any net proceeds from the exercise of the underwriters’ over-allotment option to redeem from Atlas America the number of common units equal to the number of common units issued upon the exercise of the underwriters’ over-allotment option. If the underwriters’ over-allotment option is exercised in full, Atlas America’s ownership will be reduced to 29,350,615 common units, or approximately 78.5% of our membership interests, and the ownership interest of the public unitholders will increase to 7,273,750 common units, or approximately 19.4% of our membership interests.

Principal Executive Offices and Internet Address.    Our principal executive offices are located at 311 Rouser Road, Moon Township, Pennsylvania 15108 and our telephone number is (412) 262-2830. Our internet address is www.atlasenergyresources.com.

 

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Organizational Chart.    The following chart shows the organization and ownership of Atlas Energy Resources and its subsidiaries after giving effect to this offering and the related transactions.

LOGO

 


(1)   Pursuant to his employment agreement with Atlas America, Richard D. Weber will receive a number of our common units determined by dividing $1.0 million by the initial public offering price of our common units upon completion of this offering. Amount shown is based on assumed offering price at the mid-point of the range shown on the front cover of this prospectus. These units are subject to forfeiture, vesting 25% on each anniversary of April 17, 2006.

 

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The offering

 

Units offered

6,325,000 common units; 7,273,750 common units if the underwriters exercise their over-allotment option in full.

 

Units outstanding after this offering

36,674,365 common units; and 748,456 Class A units which will be owned by our manager.

 

Use of proceeds

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of common units in this offering and related transactions. The actual sources and uses of these funds may differ from those set forth below. Please read “Use of proceeds.”

 

Sources of funds:

  
Estimated proceeds, net of estimated underwriting discounts and commissions and offering expenses, received from this offering(1)    $ 116.1 million
      

Uses of funds:

  
Distribution to Atlas America(1)(2)    $ 116.1 million
      
 
  (1)   Assumes the mid-point of the price range set forth on the cover page of this prospectus.
  (2)   If the initial public offering price exceeds the mid-point of the price range, we will distribute the excess net proceeds to Atlas America. If the initial public offering price is less than the mid-point of the price range, we will reduce the payment to Atlas America in an amount equal to the reduction in net proceeds. The distribution constitutes a reimbursement of capital expenditures incurred by Atlas America on our behalf and partial consideration for its contribution of assets to us.

We will use the net proceeds from any exercise of the underwriters’ over-allotment option to purchase additional common units to redeem an equal number of common units from Atlas America.

 

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Cash distributions

We intend to make an initial quarterly distribution, or IQD, of $0.42 per common unit to the extent we have sufficient available cash from operations after we establish appropriate cash reserves and pay fees and expenses, including payments to our manager for reimbursement of costs and expenses it incurs on our behalf. We refer to this cash as “available cash,” and we define its meaning in more detail in our limited liability company agreement found in Appendix A and in “How we make cash distributions—Distributions of Available Cash—Definition of available cash.” Our board of directors has broad discretion in establishing reserves. The cash reserves that our board of directors may establish include reserves for future cash distributions on the common units, Class A units and management incentive interests. These reserves, which could be substantial, will reduce the amount of cash available for distribution to you.

Our board of directors has adopted a policy that it will raise our quarterly cash distribution only when it believes that we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and can maintain the increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future. Our limited liability company agreement requires that, within 45 days after the end of each calendar quarter beginning with the quarter ending December 31, 2006, we distribute all of our available cash to holders of record of our units on the applicable record date.

We will adjust IQD for the period from the closing of this offering through December 31, 2006, based on the actual length of the period.

The amount of available cash in any quarter may be greater or less than the aggregate amount associated with payment of the IQD on all our common units.

In general, we will pay any cash distributions we make in the following manner:

 

  Ø   first, 98% to the holders of our common units and 2% to the holder of our Class A units, pro rata, until each unitholder has received $0.48 per unit, which we refer to as the First Target Distribution; and

 

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  Ø   after that, any amount distributed with respect to any quarter in excess of the First Target Distribution will be distributed 98% to the holders of our common units, pro rata, and 2% to the holder of our Class A units until distributions become payable with respect to our management incentive interests as described under “Management incentive interests” below.

The holder of our Class A units, initially our manager, will be entitled to 2% of our cash distributions without any obligation to make future capital contributions to us.

 

Management incentive interests

We refer to a distribution with respect to the management incentive interests as a “management incentive distribution.” Our manager will initially hold all of the management incentive interests. The table below summarizes the cash distributions attributable to common units, Class A units, and the management incentive interests.

 

    

Quarterly
distribution

level

   Marginal % interest in
distributions
 
         Class A
units
    Common
units
    Management
incentive
interests
 

IQD

   $0.42    2.0 %   98.0 %   0.0 %
First Target Distribution per unit    up to $0.48    2.0 %   98.0 %   0.0 %
Second Target Distribution per unit    above $0.48
up to $0.59
   2.0 %   83.0 %   15.0 %
After that    above $0.59    2.0 %   73.0 %   25.0 %

We will make management incentive payments to our manager if two tests are met.

The first test is the 12-Quarter Test, which requires that for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter for which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the First Target Distribution, which period we refer to as the Incentive Trigger Period:

 

  Ø  

we pay cash distributions from operating surplus to holders of our outstanding Class A and common units in an amount that on average

 

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exceeds the First Target Distribution on all of the outstanding Class A units and common units over the Incentive Trigger Period;

 

  Ø   we generate adjusted operating surplus, which is defined in “How we make cash distributions,” during the Incentive Trigger Period that on average is in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both the 12-Quarter Test and 4-Quarter Test were met; and

 

  Ø   we do not reduce the amount distributed per unit for any of the 12 quarters.

The second test is the 4-Quarter Test, which requires that for each of (i) the last four full, consecutive, non-overlapping calendar quarters in the Incentive Trigger Period, or (ii) in any four full, consecutive and non-overlapping quarters occurring after such last four quarters in the Incentive Trigger Period, provided that we have paid at least the IQD in each calendar quarter occurring between the end of the Incentive Trigger Period and the beginning of the four full, consecutive and non-overlapping quarters that satisfy the 4-Quarter Test, or (iii) in any four full, consecutive and non-overlapping quarters occurring partially within and partially after such last four quarters of the Incentive Trigger Period:

 

  Ø   we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the First Target Distribution;

 

  Ø   we generate adjusted operating surplus during each quarter in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both tests were met; and

 

  Ø   we do not reduce the amount distributed per unit for any of the four quarters.

If both tests have been met, then:

 

  Ø  

We will make a one-time management incentive distribution to the holder of our management incentive interests, at the same time that we pay the distribution to our Class A and common

 

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units for the last calendar quarter in the 4-Quarter Test, equal to the cumulative amount of the management incentive distributions that would have been paid based on the level of distributions made on our Class A and common units during the Incentive Trigger Period if the management incentive distributions were payable on a quarterly basis rather than after completion of the Incentive Trigger Period.

 

  Ø   For each calendar quarter after the two tests are satisfied:

 

  Ø   the holder of our Class A units will receive 2%, the holders of our common units will receive 83% and the holder of our management incentive interests will receive 15% of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the First Target Distribution up to $0.59, which we refer to as the Second Target Distribution; and

 

  Ø   the holder of our Class A units will receive 2%, the holders of our common units will receive 73% and the holder of our management incentive interests will receive 25% of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the Second Target Distribution.

For a further discussion of the management incentive interests, please read the information set forth under the caption “How we make cash distributions—Management Incentive Interests.”

 

Pro forma and expected ability to pay the IQD

We believe, based on the assumptions and considerations included under the caption “Cash distribution policy and restrictions on distributions,” that we will have sufficient cash available for distribution to enable us to pay the IQD of $0.42 on all of the common units and Class A units for each quarter for the twelve months ending December 31, 2007. If we had completed this offering and the related transactions on January 1, 2005, the amount of pro forma available cash generated during the twelve months ended December 31, 2005 would have been insufficient by approximately $48.9 million to pay the IQD on all our common units and Class A units. If we had completed this

 

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offering and the related transactions on October 1, 2005, the amount of pro forma available cash generated during the twelve months ended September 30, 2006 would have been insufficient by approximately $40.5 million to pay the full IQD. For a calculation of our ability to make distributions to you based on our pro forma results for the twelve months ended December 31, 2005 and September 30, 2006, please read “Cash distribution policy and restrictions on distributions.”

 

Issuance of additional units

We can issue an unlimited number of additional units without the consent of our unitholders. Please read “Risk factors—Risks Inherent in an Investment in Us—We may issue additional units without your approval, which would dilute your existing ownership interests,” “Units eligible for future sale” and “Our limited liability company agreement—Issuance of Additional Securities.”

 

Agreement to be bound by limited liability company agreement; common unit voting rights

By purchasing a common unit, you will be admitted as a member of our limited liability company and be deemed to have agreed to be bound by all of the terms of our limited liability company agreement. Pursuant to our limited liability company agreement, as a common unitholder you will be entitled to vote on the following matters:

 

  Ø   annual election of the members of our board of directors;

 

  Ø   specified amendments to our limited liability company agreement;

 

  Ø   merger of our company or the sale of all or substantially all of our assets; and

 

  Ø   dissolution of our company.

Atlas America and its affiliates will own approximately 82.7% of our common units and all of our Class A units upon completion of this offering. This will give Atlas America the ability to determine virtually all matters submitted to a unitholder vote.

 

Management agreement

Our management agreement with our manager provides for the day-to-day management of our operations and requires our manager to manage our business affairs in conformity with the policies that are approved and monitored by our board of

 

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directors. Our manager’s services are under the supervision and direction of our board of directors.

The management agreement does not have a specified term, however, our manager may not terminate the management agreement before its tenth anniversary. We may terminate the management agreement upon the affirmative vote of the holders of at least two-thirds of our outstanding common units, including units held by Atlas America and its affiliates.

 

Limitations on common unitholder actions

Our limited liability company agreement prohibits common unitholders from taking unitholder action by written consent and nullifies the common unitholder voting rights of any person other than Atlas America or its affiliates that holds 20% or more of our outstanding common units.

 

Limited call right

If, at any time, any person owns more than 87.5% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units.

 

Estimated ratio of taxable income to distributions

We estimate that if you hold the common units that you purchase in this offering through the record date for distributions for the period ending December 31, 2009, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than 50% of the cash distributed to you with respect to that period. Please read “Material tax consequences—Tax Consequences of Unit Ownership” for the basis of this estimate.

 

Material tax consequences

For discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individuals or citizens of the United States, please read “Material tax consequences.”

 

Exchange listing and trading symbol

Our common units have been approved for listing, subject to official notice of issuance, on the New York Stock Exchange under the symbol “ATN.”

 

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SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA

The following table sets forth summary historical combined financial and operating data for our predecessor, Atlas America E & P Operations, and pro forma financial data for Atlas Energy Resources, LLC, as of and for the periods indicated. Atlas America E & P Operations are the subsidiaries of Atlas America which hold its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America will transfer to us upon the completion of this offering. We derived the historical financial data as of September 30, 2004 and 2005 and December 31, 2005 and for the years ended September 30, 2004 and 2005 and three months ended December 31, 2005 from Atlas America E & P Operations’ financial statements, which were audited by Grant Thornton LLP, independent registered public accounting firm, and are included in this prospectus. We derived the historical financial data for the three months ended December 31, 2004, the nine months ended September 30, 2005 and 2006 and the balance sheet information as of September 30, 2006 from Atlas America E & P Operations’ unaudited financial statements included in this prospectus. We derived the historical financial data as of December 31, 2004 from Atlas America E & P Operations’ unaudited financial statements, which are not included in this prospectus.

The summary pro forma financial data for the year ended September 30, 2005, three months ended December 31, 2005 and nine months ended September 30, 2006 are derived from the unaudited pro forma financial statements of Atlas Energy Resources, LLC included in this prospectus. The pro forma adjustments have been prepared as if the transactions listed below had taken place on September 30, 2006, in the case of the pro forma balance sheet, or, in the case of the pro forma statements of income, as of October 1, 2004 for the year ended September 30, 2005, as of October 1, 2005 for the three months ended December 31, 2005 and as of January 1, 2006 for the nine months ended September 30, 2006. These transactions include:

 

Ø   the retention by Atlas America of the operations associated with a small gathering system;

 

Ø   the completion of this offering and the application of the net proceeds therefrom as described in “Use of proceeds;” and

 

Ø   the execution of the contribution agreement described under “Certain relationships and related transactions—Agreements Governing the Transactions—The Contribution Agreement,” pursuant to which Atlas America will assume our obligation to pay gathering fees related to our investment partnerships to Atlas Pipeline.

You should read the following summary financial data in conjunction with “Management’s discussion and analysis of financial condition and results of operations” and our financial statements and related notes appearing elsewhere in this prospectus. You should also read the pro forma information together with the unaudited pro forma financial statements and related notes included elsewhere in this prospectus.

 

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The following table includes the non-GAAP financial measures of EBITDA and segment margin. For a definition of these measures and a reconciliation to their most directly comparable financial measures calculated and presented in accordance with generally accepted accounting principles, which we refer to as GAAP, please read “—Non-GAAP Financial Measures.”

 

    Predecessor historical     Atlas Energy Resources pro forma  
    Years ended
Sept. 30,
   

Three months

ended

Dec. 31,

   

Nine months

ended

Sept. 30,

   

Year
ended
Sept. 30,
2005

    Three
months
ended
Dec. 31,
2005
   

Nine

months
ended
Sept. 30,
2006

 
     2004     2005     2004     2005     2005     2006        
                (unaudited)           (unaudited)     (unaudited)  
    (in thousands)  

Income statement data:

                 

Revenues:

                 

Gas and oil production

  $ 48,526     $ 63,499     $ 14,659     $ 24,086     $ 48,840     $ 66,696     $ 63,499     $ 24,086     $   66,696  

Partnership management:

                 

Well construction and completion

    86,880       134,338       30,558       42,145       103,780       135,329       134,338       42,145       135,329  

Administration and oversight

    8,396       9,590       2,156       2,964       7,436       8,487       9,590       2,964       8,487  

Well services

    8,430       9,552       2,248       2,561       7,304       9,498       9,552       2,561       9,498  

Gathering(1)

    4,191       4,359       1,158       1,407       3,200       6,902       4,359       1,407       6,902  
                                                                       

Total revenues

    156,423       221,338       50,779       73,163       170,560       226,912       221,338       73,163       226,912  

Direct costs:

                 

Gas and oil production and exploration(1)

    8,838       9,070       1,802       2,458       7,268       12,506       9,070       2,458       12,506  

Partnership management:

                 

Well construction and completion

    75,548       116,816       26,573       36,648       90,243       117,677       116,816       36,648       117,677  

Administration and oversight

    —         —         —         —         —         —         —        

Well services

    4,398       5,167       1,191       1,487       3,976       5,540       5,167       1,487       5,540  

Gathering(1)

    53       52       21       38       31       159       —         —         —    

Gathering fee—Atlas Pipeline(1)

    17,189       21,929       5,281       7,930       16,649       22,719       4,359       1,407       6,902  
                                                                       

Total direct costs

    106,026       153,034       34,868       48,561       118,167       158,601       135,412       42,000       142,625  

Segment margin:

                 

Gas and oil production

    39,688       54,429       12,857       21,628       41,572       54,190       54,429       21,628       54,190  

Partnership management:

                 

Well construction and completion

    11,332       17,522       3,985       5,497       13,537       17,652       17,522       5,497       17,652  

Administration and oversight

    8,396       9,590       2,156       2,964       7,436       8,487       9,590       2,964       8,487  

Well services

    4,032       4,385       1,057       1,074       3,328       3,958       4,385       1,074       3,958  

Gathering

    (13,051 )     (17,622 )     (4,144 )     (6,561 )     (13,480 )     (15,976 )     —         —         —    
                                                                       

Total segment margin

    50,397       68,304       15,911       24,602       52,393       68,311       85,926       31,163       84,287  

Other operating costs:

                 

General and administrative expense

    (10,159 )     (12,297 )     (2,147 )     (5,801 )     (10,151 )     (15,387 )     (13,064 )     (5,993 )     (15,962 )

Net expense reimbursement —affiliate

    (1,050 )     (602 )     (213 )     (163 )     (389 )     (1,041 )     (602 )     (163 )     (1,041 )

Depreciation, depletion and amortization

    (12,064 )     (14,061 )     (3,165 )     (4,916 )     (10,895 )     (16,311 )     (14,061 )     (4,916 )     (16,311 )
                                                                       

Operating income

    27,124       41,344       10,386       13,722       30,958       35,572       58,199       20,091       50,973  

Other income (expenses):

                 

Interest income

    250       317       1       32       316       653       317       32       653  

Interest expense

    —         —         —         —         —         —         (1,450 )     (413 )     (1,238 )

Other—net

    194       (238 )     1       25       (239 )     309       (238 )     25       309  
                                                                       
    444       79       2       57       77       962       (1,371 )     (356 )     (276 )
                                                                       

Net income before taxes

  $ 27,568     $ 41,423     $ 10,388     $ 13,779     $ 31,035     $ 36,534     $ 56,828     $ 19,735     $ 50,697  
                                                                       

Other financial information (unaudited):

                 

EBITDA

  $ 39,632     $ 55,484     $ 13,553     $ 18,695     $ 41,930     $ 52,845     $ 72,339     $ 25,064     $ 68,246  

 

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Table of Contents
    Predecessor historical    

Atlas Energy
Resources pro
forma

September 30,
2006

 

 
    As of and for the
years ended
September 30,
   

As of and for the

three months ended

December 31,

    As of and for the
nine months ended
September 30,
   
     2004     2005         2004             2005         2005     2006    
                (unaudited)           (unaudited)     (unaudited)  
    (in thousands)  

Cash flow data:

             

Cash provided by operating activities

  $ 42,523     $ 65,444     $ 22,399     $ 31,783     $ 43,045     $ 15,186    

Cash used in investing activities

    (32,709 )     (59,050 )     (11,591 )     (17,185 )     (47,459 )     (53,926 )  

Cash provided by (used in) financing activities

    (14,916 )     (320 )     (35 )     74       (285 )     74,428    

Capital expenditures

    33,252       59,124       11,645       17,187       47,479       54,076    

Balance sheet data (at period end):

             

Total assets

  $ 198,454     $ 270,402     $ 221,296     $ 315,052     $ 270,402     $ 416,417     $ 366,417 (2)

Liabilities associated with drilling contracts

    29,375       60,971       52,610       70,514       60,971       76,883       76,883  

Advances from affiliates

    30,008       13,897       13,854       4,257       13,897       9,575       —    

Long term debt, including current portion

    420       81       385       156       81       90       90  

Total debt

    30,428       13,978       14,239       4,413       13,978       9,665       9,665 (3)

Total equity

    109,461       146,142       19,269       154,519       146,143       239,967       189,967  

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

 

(2)   Reflects the retention of $50.0 million by Atlas America, representing the remaining proceeds from Atlas Pipeline Holdings, L.P.’s initial public offering in July 2006.

 

(3)   Reflects pro forma borrowings under our proposed credit facility to repay advances from affiliates.

 

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Table of Contents

SUMMARY RESERVE AND OPERATING DATA

The following tables show our estimated net proved reserves based on reserve reports prepared by our independent petroleum engineers, and certain summary unaudited information with respect to our production and sales of natural gas and oil. You should refer to “Risk factors,” “Management’s discussion and analysis of financial condition and results of operations,” “Business—Natural Gas and Oil Reserves” and the summary reserve report included as Appendix C in this prospectus in evaluating the material presented below. The following table includes the non-GAAP financial measure of PV-10. For a reconciliation of PV-10 to standardized measure, its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measures.”

 

     Atlas America
E&P Operations as of
   

Atlas Energy
Resources at
March 31,

2006

 
     September 30,    

December 31,

    2005    

   
          2004             2005          

Reserve data:

        

Estimated net proved reserves:

        

Natural gas (Bcf)

     142.1       158.0       157.9       158.1  

Oil (MMBbls)

     2.3       2.3       2.3       2.1  

Total (Bcfe)

     155.8       171.6       171.5       170.9  

Proved developed (Bcfe)

     108.5       117.5       121.4       120.0  

Proved undeveloped (Bcfe)

     47.3       54.1       50.1       50.9  

Proved developed reserves as % of total proved reserves(1)

     69.6 %     68.5 %     70.8 %     70.2 %

PV-10 value (in millions)(2)

   $ 320.4     $ 845.7     $ 597.1     $ 412.4  

Standardized measure (in millions)(2)

   $ 233.0     $ 606.7     $ 429.3     $ 412.4  

Weighted average reserve natural gas and oil prices(3):

        

Natural gas—per Mcf

   $ 6.91     $ 14.75     $ 10.84     $ 8.04  

Oil—per Bbl

   $ 46.00     $ 63.29     $ 57.54     $ 63.52  

 

    Years ended
September 30,
  Three months ended
December 31,
 

Nine months ended

September 30,

     2004   2005   2004   2005   2005   2006

Net production:

           

Total production (Mmcfe)

    8,371     8,573     2,113     2,213     6,460     7,250

Average daily production (Mcfe/d)

    22,875     23,490     22,968     24,054     23,665     26,554

Average natural gas sales prices per Mcf:

           

Average sales prices (including hedges)

  $ 5.84   $ 7.26   $ 6.80   $ 11.06   $ 7.41   $ 9.03

Average sales prices (excluding hedges)

  $ 5.84   $ 7.26   $ 6.80   $ 11.06   $ 7.41   $ 8.10

Average oil sales prices per Bbl:

           

Average sales prices

  $ 32.85   $ 50.91   $ 47.17   $ 56.13   $ 52.23   $ 64.59

Average unit costs per Mcfe:

           

Production costs

  $ 0.87   $ 0.95   $ 0.83   $ 1.10   $ 0.99   $ 1.42

Depletion

  $ 1.22   $ 1.42   $ 1.28   $ 2.01   $ 1.47   $ 2.04

(1)   The balance of our reserves are proved undeveloped. Our ownership in these reserves is subject to reduction as we generally contribute leasehold acreage associated with our proved undeveloped reserves to our investment partnerships in exchange for an approximate 30% equity interest in these partnerships which effectively will reduce our ownership interest in these reserves from 100% to 30% as we make these contributions.
(2)  

PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs

 

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as of the date of estimation without future escalation, without giving effect to financial hedging activities (but including our physical hedges), non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. Amounts shown for September 30, 2004 and 2005 reflect values for Atlas America E&P Operations, which pay income taxes. Amounts shown for March 31, 2006 reflect values for our reserves on a pro forma basis to reflect the contribution of assets of Atlas America to us at the closing of this offering. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure, which is, therefore, the same as the PV-10 value. Amounts shown include physical hedges but not financial hedging transactions. We estimate that if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $412.4 million to $348.7 million. For a description of our hedging transactions, please read “Business—Natural Gas Hedging.”

(3)   Natural gas and oil prices were based on NYMEX prices per Mcf and Bbl at the applicable date, with the representative price of natural gas adjusted for basis premium and Btu content to arrive at the appropriate net price. Amounts shown include physical hedges but not financial hedging transactions.

 

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Table of Contents

NON-GAAP FINANCIAL MEASURES

We include in this prospectus the non-GAAP financial measures of EBITDA, segment margin and PV-10. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with GAAP.

EBITDA

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

 

    Predecessor historical
   

Years ended September 30,

  Three months
ended December 31,
 

Nine months
ended

September 30,

     2001   2002   2003   2004   2005   2004   2005   2005   2006
    (unaudited)                   (unaudited)       (unaudited)
        (in thousands)

Net income before taxes

  $ 13,532   $ 11,197   $ 15,937   $ 27,568   $ 41,423   $ 10,388   $ 13,779   $ 31,035   $ 36,534

Plus interest expense

    —       —       —       —       —       —       —       —       —  

Plus depreciation, depletion and amortization

    9,594     9,409     9,938     12,064     14,061     3,165     4,916     10,895     16,311
                                                     

EBITDA

  $ 23,126   $ 20,606   $ 25,875   $ 39,632   $ 55,484   $ 13,553   $ 18,695   $ 41,930   $ 52,845
                                                     

 

    Atlas Energy Resources pro forma
    Year ended
September 30,
  Three months
ended
December 31,
 

Nine months

ended

September 30,

     2005   2005   2006
    (unaudited)
    (in thousands)

Net income before taxes

  $ 56,828   $ 19,735   $ 50,697

Plus interest expense

    1,450     413     1,238

Plus depreciation, depletion and amortization

    14,061     4,916     16,311
                 

EBITDA

  $ 72,339   $ 25,064   $ 68,246
                 

 

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Table of Contents

Segment margin

We define segment margin as total operating revenues less total related direct operating costs, excluding direct depreciation, depletion and amortization, for each of our operating segments. Our segment margin equals the sum of our gas and oil production and partnership management segments’ gross margins. We include segment margin as a supplemental disclosure because it represents the aggregate results of our operating segments. As an indicator of our operating performance, segment margin should not be considered an alternative to, or more meaningful than, net income or cash flow as determined in accordance with GAAP. Our segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate segment margin in the same manner. The following reconciles segment margin to our gross margin for the periods indicated:

 

   

Predecessor historical

    Atlas Energy
Resources pro forma
 
    Years ended September 30,     Three months
ended December
31,
   

Nine months

ended

September 30,

   

Year
ended
Sept. 30,

2005

   

Nine months
ended
Sept. 30,

2006

 
    2001     2002     2003     2004     2005     2004     2005     2005     2006      
                                                                   
     (unaudited)                                 (unaudited)            (unaudited)     (unaudited)  
          (in thousands)  

Segment margin:

                     

Gas and oil production

  $ 28,849     $ 20,652     $ 30,153     $ 39,688     $ 54,429     $ 12,857     $ 21,628     $ 41,572     $ 54,190     $ 54,429     $ 54,190  

Partnership management:

                     

Well construction and completion

    6,862       7,293       6,897       11,332       17,522       3,985       5,497       13,537       17,652       17,522       17,652  

Administration and oversight

    3,632       4,805       5,090       8,396       9,590       2,156       2,964       7,436       8,487       9,590       8,487  

Well services

    4,443       3,838       3,862       4,032       4,385       1,057       1,074       3,328       3,958       4,385       3,958  

Gathering

    (9,795 )     (7,307 )     (10,695 )     (13,051 )     (17,622 )     (4,144 )     (6,561 )     (13,480 )     (15,976 )     —         —    
                                                                                       

Total partnership management

    5,142       8,629       5,154       10,709       13,875       3,054       2,974       10,821       14,121       31,497       30,097  
                                                                                       

Total segment margin

    33,991       29,281       35,307       50,397       68,304       15,911       24,602       52,393       68,311       85,926       84,287  

Less segment depreciation, depletion and amortization

    (8,040 )     (9,154 )     (9,340 )     (11,326 )     (13,611 )     (2,985 )     (4,813 )     (10,595 )     (15,997 )     (13,611 )     (15,997 )
                                                                                       

Gross margin

  $ 25,951     $ 20,127     $ 25,967     $ 39,071     $ 54,693     $ 12,926     $ 19,789     $ 41,798     $ 52,314     $ 72,315     $ 68,290  
                                                                                       

PV-10

PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities (but including our physical hedges), non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

 

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PV-10 may be considered a non-GAAP measure by the SEC. We believe the presentation of the PV-10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account future corporate income taxes for which we will not be liable. Our PV-10 values as of September 30, 2004 and 2005 and December 31, 2005 reflect values for Atlas America E & P Operations, which pay income taxes. Amounts shown for March 31, 2006 reflect values for our reserves on a pro forma basis. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure, which is, therefore, the same as the PV-10 value. We further believe investors and creditors utilize our PV-10 value as a basis for comparison of the relative size and value of our reserves to other companies. Neither PV-10 value nor standardized measure reflect the impact of financial hedging transactions. The following reconciles the PV-10 value to the standardized measure (in millions):

 

    

Atlas America E&P

Operations as of

    Atlas Energy
Resources
as of
March 31, 2006
     September 30,     December 31,
2005
   
      2004     2005      

PV-10 value

   $ 320.4     $ 845.7     $ 597.1     $ 412.4

Income tax effect

     (87.4 )     (239.0 )     (167.8 )     0
                              

Standardized measure

   $ 233.0     $ 606.7     $ 429.3     $ 412.4
                              

 

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Table of Contents

 

Risk factors

Member interests in a limited liability company are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units. If any of the events described below were to occur, our business, financial condition, results of operations and cash flows could be materially adversely affected. In that case, we may not be able to pay the IQD or make future cash distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment in our company.

RISKS INHERENT IN OUR BUSINESS

We may not have sufficient cash flow from operations to pay the IQD following the establishment of cash reserves and payment of fees and expenses, including payments to our manager.

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

 

Ø   the amount of natural gas and oil we produce;

 

Ø   the price at which we sell our natural gas and oil;

 

Ø   the level of our operating costs;

 

Ø   our ability to acquire, locate and produce new reserves;

 

Ø   results of our hedging activities;

 

Ø   the level of our interest expense, which depends on the amount of our indebtedness and the interest payable on it; and

 

Ø   the level of our capital expenditures.

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

 

Ø   our ability to make working capital borrowings to pay distributions;

 

Ø   the cost of acquisitions, if any;

 

Ø   fluctuations in our working capital needs;

 

Ø   timing and collectibility of receivables;

 

Ø   restrictions on distributions imposed by lenders;

 

Ø   payments to our manager;

 


 

24


Table of Contents

Risk factors


 

Ø   the amount of our estimated maintenance capital expenditures;

 

Ø   prevailing economic conditions; and

 

Ø   the amount of cash reserves established by our board of directors for the proper conduct of our business.

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

We would not have generated sufficient available cash on a pro forma basis to have paid the IQD on all of our outstanding common units and Class A units for the twelve months ended December 31, 2005 and September 30, 2006.

The amount of available cash we will need to pay the IQD for four quarters on the common units and Class A units to be outstanding immediately after this offering is approximately $62.9 million. If we had completed the transactions contemplated in this prospectus on January 1, 2005, pro forma available cash generated during the twelve months ended December 31, 2005 would have been approximately $14.0 million, which would have been sufficient to allow us to pay approximately 22% of the IQD on our common units and Class A units during this period. If we had completed the transactions on October 1, 2005, pro forma available cash generated during the twelve months ended September 30, 2006 would have been approximately $22.4 million, which would have been sufficient to allow us to pay approximately 36% of our IQD on our common units and Class A units during this period. For a calculation of our ability to make distributions to you based on our pro forma results for the twelve months ended December 31, 2005 and September 30, 2006, please read “Cash distribution policy and restrictions on distributions.”

If we are unable to achieve the estimated EBITDA set forth in “Cash distribution policy and restrictions on distributions,” we may be unable to pay the full, or any, amount of the IQD on the common units, in which event the market price of our common units may decline substantially.

The estimated EBITDA set forth in “Cash distribution policy and restrictions on distributions” is for the twelve month period ending December 31, 2007. Our management has prepared this information and we have not received an opinion or report on it from any independent accountants. In addition, “Cash distribution policy and restrictions on distributions” includes a calculation of estimated EBITDA. The assumptions underlying this calculation are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those expected. If we do not achieve the expected results, we may not be able to pay the full, or any, amount of the IQD, in which event the market price of our common units may decline substantially.

If commodity prices decline significantly, our cash flow from operations will decline and we may have to lower our distribution or may not be able to pay distributions at all.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas and oil markets are very volatile and a drop in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices will have a significant impact on the value of our reserves and on our cash flow. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

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

 

Ø   the price and level of foreign imports;

 


 

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Ø   the level of consumer product demand;

 

Ø   weather conditions and fluctuating and seasonal demand;

 

Ø   overall domestic and global economic conditions;

 

Ø   political and economic conditions in natural gas and oil producing countries, including those in the Middle East and South America;

 

Ø   the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

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

 

Ø   technological advances affecting energy consumption;

 

Ø   domestic and foreign governmental relations, regulations and taxation;

 

Ø   the impact of energy conservation efforts;

 

Ø   the cost, proximity and capacity of natural gas pipelines and other transportation facilities; and

 

Ø   the price and availability of alternative fuels.

In the past, the prices of natural gas and oil have been extremely volatile, and we expect this volatility to continue. For example, during the nine months ended September 30, 2006, the NYMEX Henry Hub natural gas index price ranged from a high of $10.77 per MMBtu to a low of $7.55 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $80.54 per Bbl to a low of $64.04 per Bbl.

At September 30, 2006, we owned interests in 7,047 gross wells that produced, on average during the quarter ended September 30, 2006, 85.9 Mmcfe/d, or approximately 12.2 Mcfe/d per well. Producers with higher rates of production than ours are less sensitive to declining commodity prices due to the relatively fixed nature of well operating costs. Lower natural gas and oil prices may not only decrease our revenues, but also reduce the amount of natural gas and oil that we can produce economically, which would also decrease our revenues and cause us to shut in, and eventually plug and abandon, uneconomic wells.

Unless we replace our reserves, our reserves and production will decline, which would reduce our cash flow from operations and impair our ability to make distributions to our unitholders.

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Based on our March 31, 2006 reserve report, our average annual decline rate for proved developed producing reserves is approximately 11% during the first five years, approximately 6% in the next five years and less than 7% thereafter. Because total estimated proved reserves include proved undeveloped reserves at March 31, 2006, production will decline at this rate even if those proved undeveloped reserves are developed and the wells produce as expected. This rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change when we drill additional wells, make acquisitions and under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs

 


 

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depends on our generating sufficient cash flow from operations and other sources of capital, principally our sponsored investment partnerships, all of which are subject to the risks discussed elsewhere in this section.

Our estimated reserves are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

Underground accumulations of natural gas and oil cannot be measured in an exact way. Natural gas and oil reserve engineering requires subjective estimates of underground accumulations of natural gas and oil and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Our independent petroleum engineers prepare estimates of our proved reserves. Over time, our internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions by actual figures could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas and oil attributable to any particular group of properties, the classifications of reserves based on risk of recovery and estimates of the future net cash flows. For example, if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $412.4 million to $348.7 million. Our PV-10 is calculated using natural gas prices that include our physical hedges but not our financial hedges. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we ultimately recover being different from our reserve estimates.

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

 

Ø   actual prices we receive for natural gas;

 

Ø   the amount and timing of actual production;

 

Ø   the amount and timing of our capital expenditures;

 

Ø   supply of and demand for natural gas; and

 

Ø   changes in governmental regulations or taxation.

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

Any significant variance in our assumptions could materially affect the quantity and value of reserves, the amount of PV-10 described in this prospectus, and our financial condition and results of operations. In addition, our reserves or PV-10 may be revised downward or upward based upon production history,

 


 

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results of future exploitation and development activities, prevailing natural gas and oil prices and other factors. A material decline in prices paid for our production can reduce the estimated volumes of our reserves because the economic life of our wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our PV-10. Any of these negative effects on our reserves or PV-10 may decrease the value of our common units.

Our operations require substantial capital expenditures, which will reduce our cash available for distribution. In addition, each quarter we are required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available to unitholders than if actual maintenance capital expenditures were deducted.

We will need to make substantial capital expenditures to maintain our capital asset base over the long term. For the twelve months ending December 31, 2007, we estimate these expenditures to be approximately $35.0 million. These maintenance capital expenditures may include the drilling and completion of additional wells to offset the production decline from our producing properties or additions to our inventory of unproved or proved reserves. These expenditures could increase as a result of:

 

Ø   changes in our reserves;

 

Ø   changes in natural gas prices;

 

Ø   changes in labor and drilling costs;

 

Ø   our ability to acquire, locate and produce reserves;

 

Ø   changes in leasehold acquisition costs; and

 

Ø   government regulations relating to safety and the environment.

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

We will be required to make substantial capital expenditures to increase our asset base. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished.

The natural gas and oil industry is capital intensive. We intend to finance our future capital expenditures with capital raised through our sponsored investment partnerships, cash flow from operations and bank borrowings. In particular, our forecast of cash available for distribution for the twelve month period ending December 31, 2007 assumes that we will raise $270.0 million from third parties through our

 


 

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investment partnerships. This amount of capital is significantly more than the $199.8 million we raised during the twelve months ended September 30, 2006 and significantly more than the average annual amount of $152.0 million we raised for the three fiscal years ended September 30, 2006. If we are unable to obtain sufficient capital funds on satisfactory terms, we may be unable to increase or maintain our inventory of properties and reserve base, or be forced to curtail drilling or other activities. This would result in a decline in our revenues and our ability to increase cash distributions may be diminished. If we do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions.

Changes in tax laws may impair our ability to obtain capital funds through investment partnerships.

Under current federal tax laws, there are tax benefits to investing in investment partnerships such as those we sponsor, including deductions for intangible drilling costs and depletion deductions. Changes to federal tax law that reduce or eliminate these benefits may make investment in our investment partnerships less attractive and, thus, reduce our ability to obtain funding from this significant source of capital funds. A recent change to federal tax law that may affect us is the Jobs and Growth Tax Relief Reconciliation Act of 2003, which reduced the maximum federal income tax rate on long-term capital gains and qualifying dividends to 15% through 2008. These changes may make investment in our investment partnerships relatively less attractive than investments in assets likely to yield capital gains or qualifying dividends.

Our proposed credit facility will have substantial restrictions and financial covenants. A default under these provisions could cause all of our debt to be immediately due and restrict our payment of distributions to our unitholders.

Our proposed revolving credit facility will restrict our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations. We will also be required to comply with specified financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flow from our operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the credit facility could result in a default, which could cause our existing indebtedness to be immediately due and restrict our payment of distributions to our unitholders.

Our future debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Following this offering, we anticipate that we will have the ability to borrow $155 million under our proposed credit facility, subject to borrowing base limitations in the credit agreement. Our future indebtedness could have important consequences to us, including:

 

Ø   our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

 

Ø   covenants contained in our credit arrangements will require us to meet financial tests that may affect our flexibility in planning for and reacting to changes in our business, including possible acquisition opportunities;

 

Ø   we will need a substantial portion of our cash flow to make principal and interest payments on our indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and distributions to unitholders; and

 


 

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Ø   our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

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

We may not be able to continue to raise funds through our investment partnerships at the levels we have recently experienced, which may in turn restrict our ability to maintain our drilling activity at the levels recently experienced.

We have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities. Accordingly, the amount of development activities we undertake depends in large part upon our ability to obtain investor subscriptions to invest in these partnerships. During the past three fiscal years we have raised successively larger amounts of funds through these investment partnerships, raising $107.7 million in 2004, $148.7 million in 2005 and $199.8 million in 2006. In addition, our forecast of cash available for distribution for the twelve month period ending December 31, 2007 assumes that we will raise $270.0 million from third parties through our investment partnerships. In the future, we may not be successful in raising funds through these investment partnerships at the same levels we have recently experienced, and we also may not be successful in increasing the amount of funds we raise as we have done in recent years. Our ability to raise funds through our investment partnerships depends in large part upon the perception of investors of their potential return on their investment and their tax benefits from investing in them, which perception is influenced significantly by our historical track record of generating returns and tax benefits to the investors in our existing partnerships.

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

Our fee-based revenues may decline if we are unsuccessful in continuing to sponsor investment partnerships, and our fee-based revenue may not increase at the same rate as recently experienced if we are unable to raise funds at the same or higher levels than we have recently experienced.

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

 


 

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

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

Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Competition is intense for the acquisition of leases considered favorable for the development of natural gas and oil in commercial quantities. Product availability and price are the principal means of competition in selling oil and natural gas. Many of our competitors possess greater financial and other resources than ours which may enable them to identify and acquire desirable properties and market their natural gas and oil production more effectively than we do.

Our business depends on the gathering and transportation facilities of Atlas Pipeline. Any limitation in the availability of those facilities would interfere with our ability to market the natural gas we produce and could reduce our revenues and cash available for distribution.

Atlas Pipeline gathers more than 90% of our current production. The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by Atlas Pipeline and other third parties. The amount of natural gas that can be produced and sold is subject to curtailment in circumstances such as pipeline interruptions due to scheduled and unscheduled maintenance or excessive pressure or physical damage to the gathering or transportation system. The curtailments arising from these and similar circumstances may last from a few days to several months.

If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we would have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources.

At the closing, we will become a party to a gas gathering agreement with Atlas Pipeline which requires, among other things, paying Atlas Pipeline gathering fees for gathering our gas. The gathering agreement is a continuing obligation and not terminable by us, except that if Atlas Pipeline’s general partner is removed without cause, then no gathering fees will be due under the agreement with respect to new wells drilled by us. Atlas America will assume our obligation to pay these gathering fees pursuant to the contribution agreement to be executed upon completion of this offering, and we will agree to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest. The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our

 


 

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investment partnerships for gathering services. For the twelve months ended September 30, 2006, this excess amount was approximately $23.3 million. If Atlas America defaulted on its obligation to us under the assumption agreement to pay gathering fees to Atlas Pipeline, we would be liable to Atlas Pipeline for the payment of the fees, which would reduce our income and cash available for distributions to unitholders.

We depend on certain key customers for sales of our natural gas. To the extent these customers reduce the volumes of natural gas they purchase from us, our revenues and cash available for distribution could decline.

Our natural gas is sold under contracts with various purchasers. Under a natural gas supply agreement with Hess Corporation, which expires on March 31, 2009, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our investment partnerships. During fiscal 2005, natural gas sales to Hess Corporation accounted for 12% of our total revenues, and during the twelve months ended September 30, 2006, Hess Corporation accounted for 10% of our total revenues. To the extent Hess Corporation and our other key customers reduce the amount of natural gas they purchase from us, our revenues and cash available for distributions to unitholders could temporarily decline in the event we are unable to sell to additional purchasers.

Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash available for distribution.

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

Because we handle natural gas and oil, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment.

The operations of our wells and other facilities are subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

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

 

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

 

Ø   the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws that impose requirements for the handling and disposal of waste from our facilities; and

 

Ø   the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, also known as “Superfund,” and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of

 


 

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remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, the federal Oil Pollution Act and analogous state laws and regulations, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed of or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

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

Many of our leases are in areas that have been partially depleted or drained by offset wells.

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

Our identified drilling location inventories are susceptible to uncertainties that could materially alter the occurrence or timing of our drilling activities, which may result in lower cash from operations and, therefore, may impact our ability to pay distributions.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, natural gas prices, costs and drilling results. In addition, Wright and Company, Inc. has not assigned any proved reserves to the over 2,700 unproved potential drilling locations we have identified and therefore there may exist greater uncertainty with respect to the success of drilling wells at these drilling locations. Our final determination on whether to drill any of these drilling locations will be dependent upon the factors described above as well as, to some degree, the results of our drilling activities with respect to our proved drilling locations. Because of these uncertainties, we do not know if the numerous drilling locations we have identified will be drilled within our expected timeframe or will ever be drilled or if we will be able to produce natural gas and oil from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from our anticipated drilling activities. Our forecast of estimated cash available for distribution to our unitholders is based on an assumption that we will drill 888 gross wells on behalf of investment partnerships during the twelve months ending December 31, 2007, which number of wells exceeds the total number of currently identified proved undeveloped well locations. In the event that we are unable to continue to identify drilling locations that we believe will provide us attractive development opportunities in sufficient quantities to support our growth plans, we may be required to reduce the amount of funds raised through our investment partnerships, which in turn would result in a reduction in the fee-based revenue that we would otherwise realize and therefore would negatively impact our ability to make cash distributions to our unitholders at the initial quarterly distribution rate.

 


 

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Some of our undeveloped leasehold acreage is subject to leases that may expire in the near future.

Leases covering approximately 12,300 of our 516,200 net acres, or 2%, are scheduled to expire on or before September 30, 2007. If we are unable to renew these leases, or any leases scheduled for expiration beyond September 30, 2007, on favorable terms, we will lose the right to develop the acreage that is covered by an expired lease and our production would decline, which would reduce our cash flows from operations and could impair our ability to make distributions.

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

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

 

Ø   the high cost, shortages or delivery delays of equipment and services;

 

Ø   unexpected operational events and drilling conditions;

 

Ø   adverse weather conditions;

 

Ø   facility or equipment malfunctions;

 

Ø   title problems;

 

Ø   pipeline ruptures or spills;

 

Ø   compliance with environmental and other governmental requirements;

 

Ø   unusual or unexpected geological formations;

 

Ø   formations with abnormal pressures;

 

Ø   injury or loss of life;

 

Ø   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;

 

Ø   fires, blowouts, craterings and explosions; and

 

Ø   uncontrollable flows of natural gas or well fluids.

Any one or more of the factors discussed above could reduce or delay our receipt of drilling and production revenues, thereby reducing our earnings, and could reduce revenues in one or more of our investment partnerships, which may make it more difficult to finance our drilling operations through sponsorship of future partnerships. In addition, any of these events can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

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

 


 

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

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

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

Hedging transactions may limit our potential gains or cause us to lose money.

Pricing for natural gas has been volatile and unpredictable for many years. To limit exposure to changing natural gas prices, we use financial and physical hedges for our natural gas production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to smaller quantities than those projected to be available at any delivery point. In addition, we may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future.

By removing the price volatility from a significant portion of our natural gas production, we have reduced, but not eliminated, the potential effects of changing natural gas prices on our cash flow from operations for those periods. Furthermore, while intended to help reduce the effects of volatile natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if natural gas prices were to rise substantially over the price established by the hedge. Under circumstances in which, among other things, production is substantially less than expected, the counterparties to our futures contracts fail to perform under the contracts or a sudden, unexpected event materially impacts natural gas prices, we may be exposed to the risk of financial loss.

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

We serve as the managing general partner of 91 investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in our investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets. Furthermore, investor partners in some of our investment partnerships have the right to present their interests for purchase by us, as managing general partner, up to 5% to 10% of the total limited partner interests in any calendar year.

 


 

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Our revenues may decrease if investors in our investment partnerships do not receive a minimum return.

We have agreed to subordinate up to 50% of our share of production revenues to specified returns to the investor partners in our investment partnerships, typically 10% per year for the first five years of distributions. Thus, our revenues from a particular partnership will decrease if it does not achieve the specified minimum return and our ability to make distributions to unitholders may be impaired. We have not subordinated our share of revenues from any of our investment partnerships since March 2005, but did subordinate $91,000 in fiscal 2005, $335,000 in fiscal 2004 and $362,000 in fiscal 2003.

If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

We are subject to comprehensive federal, state, local and other laws and regulations that could increase the cost and alter the manner or feasibility of our doing business.

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

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

 


 

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RISKS INHERENT IN AN INVESTMENT IN US

Atlas America and its affiliates will own a controlling interest in us upon completion of this offering.

Upon completion of this offering, Atlas America and its affiliates will own approximately 82.7% of our common units and all of our Class A units. Accordingly, Atlas America will possess a controlling vote on all matters submitted to a vote of our unitholders, including election of our board of directors. As long as Atlas America owns a controlling interest in us, it will be able to approve or disapprove matters submitted to members for a vote irrespective of the vote of persons buying common units in this offering. Atlas America will be able to cause a change of control of our company. This concentration of ownership may have the effect of preventing or discouraging transactions involving an actual or a potential change of control of our company, regardless of whether a premium is offered over then-current market prices. Moreover, even if subsequent issuances result in Atlas America holding less than a majority of the common units, it will be able to determine matters requiring class voting so long as it controls the Class A units.

Our limited liability company agreement limits and modifies our directors’ and officers’ fiduciary duties.

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

 

Ø   our directors and officers will not have any liability to us or our unitholders for decisions made in good faith, which is defined so as to require that they believed the decision was in our best interests; and

 

Ø   our directors and officers will not be liable for monetary damages to us or our unitholders for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the directors or officers acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such conduct was unlawful.

Members of our board of directors and Atlas America and its affiliates, including our manager, may have conflicts of interest with us.

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

 

Ø   Our limited liability company agreement gives our board of directors broad discretion in establishing cash reserves for the proper conduct of our business, which will affect the amount of cash available for distribution. For example, our board of directors will use its reasonable discretion to establish and maintain cash reserves sufficient to maintain our asset base.

 

Ø   Our manager will recommend to our board of directors the timing and extent of our drilling program and related capital expenditures, asset purchases and sales, and financing alternatives and reserve adjustments, all of which will affect the amount of cash that we distribute to our unitholders.

 

Ø   In some instances our board of directors may cause us to borrow funds in order to permit us to pay cash distributions to our unitholders, even if the purpose or effect of the borrowing is to make management incentive distributions.

 


 

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Ø   Except as provided in our omnibus agreement with Atlas America, members of our board of directors and Atlas America and its affiliates, including our manager, are not prohibited from investing or engaging in other businesses or activities that compete with us.

 

Ø   We do not have any employees and rely solely on employees of our manager and its affiliates. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and our affiliates regarding the availability of these officers to manage us.

You will experience immediate and substantial dilution of $16.01 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $3.99 per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $16.01 per common unit. Please read “Dilution.”

Upon completion of this offering, we will be a “controlled company” within the meaning of NYSE rules and, as a result, will qualify for, and intend to rely on, exemptions from some of the NYSE listing requirements with respect to independent directors.

Because Atlas America will control a majority of our outstanding common units upon completion of this offering, we will be a controlled company within the meaning of NYSE rules which exempt controlled companies from the following corporate governance requirements:

 

Ø   the requirement that a majority of the board of directors consist of independent directors;

 

Ø   the requirement to have a nominating/corporate governance committee of the board of directors, composed entirely of members who are independent as defined by NYSE rules, that is responsible for identifying individuals qualified to become board members, consistent with criteria approved by the board, selection of board nominees for the next annual meeting of shareholders, development of corporate governance guidelines and oversight of the evaluation of the board and management;

 

Ø   the requirement to have a compensation committee of the board of directors, composed entirely of independent directors, that is responsible for reviewing and approving corporate goals and objectives relevant to chief executive officer compensation, evaluation of the chief executive officer’s performance in light of the goals and objectives, determination and approval of the chief executive officer’s compensation, and making recommendations to the board with respect to compensation of other executive officers and incentive compensation and equity-based plans that are subject to board approval; and

 

Ø   the requirement for an annual performance evaluation of the nominating/corporate governance and compensation committees.

For so long as we remain a controlled company, we do not intend to have a majority of independent directors or nominating/corporate governance or compensation committees. Accordingly, you will not have the same protections afforded to shareholders of companies that are subject to all of the NYSE corporate governance requirements.

We may issue additional units without your approval, which would dilute your existing ownership interests.

We may issue an unlimited number of units of any type, including common units, without the approval of our unitholders. The issuance of additional units or other equity securities may have the following effects:

 

Ø   your proportionate ownership interest in us may decrease;

 


 

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

 

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

 

Ø   the market price of the common units may decline.

Our limited liability company agreement provides for a limited call right that may require you to sell your common units at an undesirable time or price.

If, at any time, any person owns more than 87.5% of the common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of the common units. As a result, you may be required to sell your common units at an undesirable time or price and therefore may receive a lower or no return on your investment. You may also incur tax liability upon a sale of your units. For additional information about the call right, please read “Our limited liability company agreement—Limited Call Right.”

Unitholders may have limited liquidity for their common units, a trading market may not develop for the units and you may not be able to resell your units at the initial public offering price.

There has been no public market for the common units before this offering. After the offering, there will be 6,325,000 publicly-traded common units outstanding, assuming no exercise of the underwriters’ option to purchase additional common units. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the units.

If the unit price declines after the initial public offering, you could lose a significant part of your investment.

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

 

Ø   changes in securities analysts’ recommendations and their estimates of our financial performance;

 

Ø   the public’s reaction to our press releases, announcements and our filings with the SEC;

 

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

 

Ø   changes in market valuations of similar companies;

 

Ø   departures of key personnel;

 

Ø   commencement of or involvement in litigation;

 

Ø   variations in our quarterly results of operations or those of other natural gas and oil companies;

 

Ø   variations in the amount of our quarterly cash distributions;

 

Ø   future issuances and sales of our units; and

 

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

 


 

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

Unitholders may have liability to repay distributions.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Revised Limited Liability Company Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible

distribution, unitholders who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited liability company for the distribution amount. A purchaser of common units who becomes a unitholder is liable for the obligations of the transferring unitholder to make contributions to the limited liability company that are known to such purchaser of units at the time it became a member and for unknown obligations if the liabilities could be determined from our limited liability company agreement.

Our manager may transfer its interests in us to a third party without common unitholder consent.

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

Atlas America may sell common units in the future, which could reduce the market price of our outstanding units.

Following the completion of this offering, Atlas America will own 30,299,365 common units. In addition, our manager will have the right to convert its Class A units and management incentive interests into common units if we terminate the management agreement, and its Class A units will automatically convert into common units, and it will have the option of converting its management incentive interests, if the common unitholders vote to eliminate the special voting rights of our Class A units. We have agreed to register for sale common units held by Atlas America and its affiliates. These registration rights allow Atlas America, our manager and their affiliates to request registration of their common units and to include any of those units in a registration of other securities by us. If Atlas America and its affiliates were to sell a substantial portion of their units, it could reduce the market price of our outstanding common units. Please also read “Material tax consequences—Disposition of Common Units—Constructive termination.”

We depend on our manager and Atlas America, and may not find suitable replacements if the management agreement terminates.

We have no employees. Our support personnel are employees of Atlas America. We have no separate facilities and completely rely on our manager and, because our manager has no direct employees, Atlas America. If our management agreement terminates, we may be unable to find a suitable replacement for them.

Our management agreement was not negotiated at arm’s-length and, as a result, may not be as favorable to us as if it had been negotiated with a third party.

Our officers and four of our directors, Edward E. Cohen, Jonathan Z. Cohen, Richard D. Weber and Matthew A. Jones, are officers or directors of our manager, and Messrs. Cohen are directors of Atlas

 


 

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America. As a consequence, our management agreement was not the result of arm’s-length negotiations and its terms may not be as favorable to us as if it had been negotiated with an unaffiliated third party.

Expense reimbursements due to our manager under our management agreement will reduce cash available for distribution to our unitholders.

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

Termination of the management agreement by us is difficult.

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

Our manager’s liability is limited under the management agreement, and we have agreed to indemnify our manager against certain liabilities.

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

Our limited liability company agreement restricts the voting rights of unitholders owning 20% or more of our common units.

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

 


 

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

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

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

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

TAX RISKS TO UNITHOLDERS

For a discussion of the expected material federal income tax consequences of owning and disposing of common units, see “Material tax consequences.”

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, taxes paid, if any, would reduce the amount of cash available for distribution.

The anticipated after-tax benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter that affects us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed as corporate distributions, and no income, gain, loss, deduction or credit would flow through to you. Because a tax may be imposed on us as a corporation, our cash available for distribution to our unitholders could be reduced. Therefore, our treatment as a corporation could result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and therefore result in a substantial reduction in the value of our common units.

Current law or our business may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread

 


 

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state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to you would be reduced. Our limited liability company agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the IQD amount and the incentive distribution amounts will be adjusted to reflect the impact of that law on us.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

You will be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from your share of our taxable income.

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

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

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

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

We will treat each purchaser of our common units as having the same tax benefits without regard to the common units purchased. The IRS may challenge this treatment, which could reduce the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns. Please read “Material tax consequences — Uniformity of Common Units” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

 


 

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

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

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

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

You may be subject to state and local taxes and return filing requirements in states where you do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if you do not reside in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially do business and own assets in Pennsylvania, New York, Ohio and Tennessee. As we make acquisitions or expand our business, we may do business or own assets in other states in the future. It is the responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be required of such unitholder. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in the common units.

 


 

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Cautionary note regarding forward-looking statements

This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about our:

 

Ø   business strategy;

 

Ø   financial strategy;

 

Ø   drilling locations;

 

Ø   natural gas and oil reserves;

 

Ø   realized natural gas and oil prices;

 

Ø   production volumes;

 

Ø   lease operating expenses, general and administrative expenses and finding and development costs;

 

Ø   future operating results; and

 

Ø   plans, objectives, expectations and intentions.

All of these types of statements, other than statements of historical fact included in this prospectus, are forward-looking statements. These forward-looking statements may be found in the “Prospectus summary,” “Risk factors,” “Cash distribution policy and restrictions on distributions,” “Management’s discussion and analysis of financial condition and results of operations,” “Business” and other sections of this prospectus. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” the negative of such terms or other comparable terminology.

The forward-looking statements contained in this prospectus are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this prospectus are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the “Risk factors” section and elsewhere in this prospectus. All forward-looking statements speak only as of the date of this prospectus. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

 


 

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Use of proceeds

The following table sets forth the estimated sources and uses of the funds we expect to receive from the sale of common units in this offering and related transactions. The actual sources and uses of these funds may differ from those set forth below.

 

Sources of funds (in millions):

  

Estimated proceeds, net of estimated underwriting discounts and commissions and offering expenses, received from this offering(1)

   $ 116.1
      

Uses of funds (in millions):

  

Distribution to Atlas America(1)(2)

   $ 116.1
      

(1)   We estimate that we will receive net proceeds of approximately $116.1 million from the sale of the 6,325,000 common units offered by this prospectus, assuming an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and after deducting estimated underwriting discounts and commissions of $8.9 million and estimated offering expenses of $1.5 million.
(2)   If the initial public offering price exceeds the mid-point of the price range, we will distribute the excess net proceeds to Atlas America. If the initial public offering price is less than the mid-point of the price range, we will reduce the payment to Atlas America in an amount equal to the reduction in net proceeds. The distribution constitutes a reimbursement of capital expenditures incurred by Atlas America on our behalf and partial consideration for its contribution of assets to us.

If the underwriters’ over-allotment option is exercised, we will use the additional net proceeds to purchase a number of units from Atlas America equal to the number of units issued upon exercise of the option. If the underwriters’ over-allotment option is exercised in full, Atlas America’s ownership will be reduced from 30,299,365 common units to 29,350,615 common units, reducing Atlas America’s limited liability company interest in us from approximately 81.0% to approximately 78.5%.

 


 

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Capitalization

The following table sets forth our capitalization as of September 30, 2006 (1) on an historical basis and (2) on a pro forma basis to give effect to the offering and related transactions and the application of the net proceeds of this offering as described in “Use of Proceeds.” In each case, the table assumes an initial public offering price of $20.00 per common unit, the mid-point of the price range set forth on the front cover of this prospectus, and further assumes that the underwriters’ over-allotment option is not exercised. The table is derived from, and should be read in conjunction with, and is qualified in its entirety by reference to, the pro forma and historical financial statements and notes thereto included elsewhere in this prospectus. You should also read this table in conjunction with “Prospectus summary—The Transactions and Our LLC Structure” and “Management’s discussion and analysis of financial condition and results of operations.”

 

     As of September 30, 2006
        Historical        Pro forma  
     (in thousands)

Cash and cash equivalents(1)

   $ 56,605    $ 5,106
             

Credit facility(2)

     —        9,575

Advances from affiliates

     9,575      —  

Other debt

     90      90
             

Total debt

     9,665      9,665

Equity

     

Combined equity

     222,555      —  

Accumulated other comprehensive income

     17,412      17,412

Held by public:

     

Common units

     —        116,145

Held by Atlas America and affiliates(3):

     

Common units

     —        52,959

Held by our manager:

     

Class A units

     —        3,451
             

Total equity

     239,967      189,967
             

Total capitalization

   $ 249,632    $ 199,632
             

(1)   Pro forma cash and cash equivalents reflects the retention of $50.0 million by Atlas America, representing the remaining proceeds from the Atlas Pipeline Holdings initial public offering in July 2006.
(2)   Reflects pro forma borrowings of $9.6 million under our proposed credit facility to repay advances from affiliates.
(3)   Includes 50,000 restricted common units estimated to be issued to Richard D. Weber upon completion of this offering.

 


 

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Dilution

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the net tangible book value per unit after the offering. Net tangible book value is our total tangible assets less total liabilities. Assuming an initial public offering price of $20.00 per common unit, on a pro forma basis as of September 30, 2006, after giving effect to the formation transactions and this offering and the application of the net proceeds of this offering, and assuming the underwriters’ over-allotment option is not exercised, our net tangible book value would have been approximately $149.4 million or $3.99 per common unit. Purchasers of common units in the offering will experience substantial and immediate dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per unit

 

  $ 20.00

Pro forma net tangible book value per common unit before the offering(1)

   $ 6.41    

Decrease in net tangible book value per common unit attributable to purchasers in the offering

     (2.42 )  
          

Less: Pro forma net tangible book value per common unit after the offering(2)

 

    3.99
        

Immediate dilution in net tangible book value per common unit

 

  $ 16.01
        

(1)   Determined by dividing the total number of common units (30,349,365) and Class A units (748,456) to be issued to Atlas America and its affiliates into the pro forma net tangible book value of the contributed assets and liabilities.
(2)   Determined by dividing the total number of common units (36,674,365) and Class A units (748,456) to be outstanding after the offering into our pro forma net tangible book value, after giving effect to the application of the net proceeds of the offering.

The following table sets forth the number of Class A and common units that will be issued by us and the total consideration contributed to us by Atlas America and its affiliates with respect to their Class A and common units and by the purchasers of common units in this offering upon the consummation of the transactions contemplated by this prospectus:

 

     Class A and common
units acquired
    Total consideration  
      Number    Percent    

Amount

(in thousands)

   Percent  

Atlas America and its affiliates(1)

   31,047,821    83.0 %   $ 73,822    37 %

Richard D. Weber(2)

   50,000    0.1 %     —      —    

New investors

   6,325,000    16.9 %     126,500    63 %
                        

Total

   37,422,821    100 %   $ 200,322    100 %
                        

 


 

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(1)   Atlas America’s assets contributed to us will be recorded at historical book value, rather than fair value, in accordance with GAAP. The difference between historical book value and the purchase price has been recorded as a reduction in unitholders’ equity. Book value of the consideration provided by Atlas America and its affiliates, as of September 30, 2006, after giving effect to the application of the net proceeds of the offering, is as follows:

 

     (in thousands)  

Book value of net assets contributed by Atlas America

   $ 239,967  

Less: distribution of the net proceeds from the sale of common units

     (116,145 )

Less: remaining proceeds from Atlas Pipeline Holdings’ initial public offering

     (50,000 )
        

Total consideration

   $ 73,822  
        

 

(2)   Pursuant to his employment agreement with Atlas America, Richard D. Weber will receive a number of our common units determined by dividing $1.0 million by the initial public offering price of our common units upon completion of this offering. Amount shown is based on assumed offering price at the mid-point of the range shown on the front cover of this prospectus. These units are subject to forfeiture, vesting 25% on each anniversary of April 17, 2006.

 


 

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How we make cash distributions

INITIAL QUARTERLY DISTRIBUTION

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our board of directors, taking into account the terms of our limited liability company agreement. We intend to distribute to the holders of common units and Class A units on a quarterly basis at least the IQD of $0.42 per unit, or $1.68 per unit per year to the extent we have sufficient available cash after we establish appropriate reserves and pay fees and expenses, including payments to our manager in reimbursement of costs and expenses it incurs on our behalf. Our IQD is intended to reflect the level of cash that we expect to be available for distribution per common unit and Class A unit each quarter. There is no guarantee we will pay the IQD in any quarter and we will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under our proposed credit agreement. We would not have generated sufficient available cash on a pro forma basis to have paid the IQD on all of our outstanding common units and Class A units for the twelve months ended December 31, 2005 and September 30, 2006. Please read “Risk factors—Risks Inherent in Our Business—We would not have generated sufficient available cash on a pro forma basis to have paid the IQD on all of our outstanding common units and Class A units for the twelve months ended December 31, 2005 and September 30, 2006,” “Cash distribution policy and restrictions on distributions—Unaudited Pro Forma Available Cash for Distribution” and “Management’s discussion and analysis of financial condition and results of operations.” It is the current policy of our board of directors that we should raise our quarterly cash distribution only when the board believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our capital asset base, and (ii) we can maintain such an increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future when and if it determines such alteration to be appropriate.

DISTRIBUTIONS OF AVAILABLE CASH

Overview

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

Definition of available cash

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

 

Ø   less the amount of cash reserves established by our board of directors to:

 

  Ø   provide for the proper conduct of our business (including reserves for future capital expenditures and credit needs);

 

  Ø   comply with applicable law and any of our debt instruments or other agreements; and

 

  Ø   provide funds for distributions (1) to our unitholders for any one or more of the next four quarters or (2) with respect to our management incentive interests;

 

Ø   plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

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

 


 

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OPERATING SURPLUS AND CAPITAL SURPLUS

General

All cash we distribute to unitholders will be characterized as either “operating surplus” or “capital surplus.” Our limited liability company agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of operating surplus

Operating surplus generally means:

 

Ø   $40.0 million (as described below); plus

 

Ø   all of our cash receipts after the closing of this offering, including working capital borrowings but excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business; plus

 

Ø   working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

 

Ø   cash distributions paid on equity securities that we may issue after this offering to finance all or a portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset is placed into service or the date that it is abandoned or disposed of; less

 

Ø   our operating expenditures (as defined below); less

 

Ø   the amount of cash reserves established by our board of directors to provide funds for future operating expenditures; less

 

Ø   all working capital borrowings not repaid within 12 months after having been incurred.

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

Operating expenditures generally means all of our cash expenditures, including taxes, reimbursement of expenses to our manager, payments made in the ordinary course of business on commodity hedge contracts, director and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, but do not include:

 

Ø   repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus when the repayment actually occurs;

 

Ø   payments (including prepayments and prepayment penalties) of principal and premium on indebtedness, other than working capital borrowings;

 

Ø   expansion capital expenditures;

 

Ø   actual maintenance capital expenditures;

 

Ø   investment capital expenditures;

 

Ø   payment of transaction expenses relating to interim capital transactions; or

 

Ø   distributions to our members (including distributions with respect to our management incentive interests).

 


 

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As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $40.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including certain cash distributions on equity securities in operating surplus would be to increase operating surplus by the amount of the cash distributions. As a result, we may also distribute as operating surplus up to the amount of the cash distributions we receive from non-operating sources.

None of actual maintenance capital expenditures, investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because actual maintenance capital expenditures, investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset (such as equipment or reserves) during the period from when we enter into a binding commitment to commence construction, acquisition or improvement of a capital asset until the earlier to occur of the date any such capital asset is placed into service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus (except, in the case of maintenance capital expenditures, to the extent such interest payments and distributions are included in estimated maintenance capital expenditures).

Capital expenditures

Maintenance Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures we expect to make on an ongoing basis to maintain our capital asset base at a steady level over the long term. Examples of maintenance capital expenditures include capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, and plugging and abandonment costs. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a replacement asset during the period beginning on the date that we enter into a binding obligation to commence construction or development of the replacement asset and ending on the earlier to occur of the date the replacement asset is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be very large and irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus. To eliminate the effect on operating surplus of these fluctuations, our limited liability company agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain our asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and approval by our board of directors, including a majority of our conflicts committee, at least once a year. We will make the estimate at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital

 


 

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expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Cash distribution policy and restrictions on distributions.”

The use of estimated maintenance capital expenditures in calculating operating surplus will have the following effects:

 

Ø   it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the IQD to be paid on all the units for that quarter and subsequent quarters;

 

Ø   it will increase our ability to distribute as operating surplus cash we receive from non-operating sources;

 

Ø   it will be more difficult for us to raise our distribution above the IQD and pay management incentive distributions; and

 

Ø   it will reduce the likelihood that a large maintenance capital expenditure during the Incentive Trigger Period will prevent the payment of a management incentive distribution in respect of the Incentive Trigger Period since the effect of an estimate is to spread the expected expense over several periods, thereby mitigating the effect of the actual payment of the expenditure on any single period.

Expansion Capital Expenditures

Expansion capital expenditures are those capital expenditures that we expect to make to expand our capital asset base for the longer than short term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interests, to the extent such expenditures are incurred to increase our capital asset base. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of a capital improvement during the period beginning on the date that we enter into a binding obligation to commence construction or development of the capital improvement and ending on from the earlier to occur of the commencement of construction or the financing of the capital improvement until the earlier to occur of the date the capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment Capital Expenditures

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of our undeveloped properties in excess of maintenance capital expenditures, but which are not expected to expand our asset base for more than the short term.

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our board of directors, including a majority of our conflicts committee, based upon its good faith determination.

 


 

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Definition of capital surplus

Capital surplus will generally be generated only by:

 

Ø   borrowings other than working capital borrowings;

 

Ø   sales of debt and equity securities; and

 

Ø   sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

Characterization of cash distributions

We will treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since we began operations equals the operating surplus as of the most recent date of determination of available cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

DISTRIBUTIONS OF AVAILABLE CASH FROM OPERATING SURPLUS

We will make distributions of available cash from operating surplus for any quarter in the following manner:

 

Ø   first, 98% to the common unitholders, pro rata, and 2% to the holder of our Class A units, until we distribute $0.48 per unit for the quarter (the “First Target Distribution”); and

 

Ø   after that, any amount distributed with respect to the quarter in excess of the First Target Distribution per common unit will be distributed 98% to the holders of the common units, pro rata, and 2% to the holder of our Class A units until distributions become payable with respect to our management incentive interests as described in “—Management Incentive Interests” below.

The Class A units will be entitled to 2% of all cash distributions from operating surplus, without any requirement for future capital contributions by the holders of such Class A units, even if we issue additional common units or other senior or subordinated equity securities in the future. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

MANAGEMENT INCENTIVE INTERESTS

Management incentive interests represent the right to receive increasing amounts of quarterly distributions of available cash from operating surplus after we have made payments in excess of the First Target Distribution and the tests described below have been met. Our manager currently holds the management incentive interests, which are evidenced by the Class C limited liability company interests, but may transfer these rights separately from its Class A units, subject to restrictions in our limited liability company agreement.

Before the end of the Incentive Trigger Period, which we define below, we will not pay any management incentive distributions. To the extent, however, that during the Incentive Trigger Period we distribute available cash from operating surplus in excess of the First Target Distribution, our board of directors intends to cause us to reserve an amount for payment of a one-time management incentive distribution

earned during the Incentive Trigger Period, after such period ends. If during the Incentive Trigger Period

 


 

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we fail to satisfy a condition specified in the next paragraph, our board of directors will cause any such reserved amount to be released from that reserve and restored to available cash.

The 12-Quarter Test and the 4-Quarter Test

We will make management incentive payments if two tests are met. The first test is the 12-Quarter Test, which requires that for the 12 full, consecutive, non-overlapping calendar quarters that begin with the first calendar quarter with respect to which we pay per unit cash distributions from operating surplus to holders of Class A and common units in an amount equal to or greater than the First Target Distribution (we refer to such 12-quarter period as the Incentive Trigger Period):

 

Ø   we pay cash distributions from operating surplus to holders of our outstanding Class A and common units in an amount that on average exceeds the First Target Distribution on all of the outstanding Class A units and common units over the Incentive Trigger Period;

 

Ø   we generate adjusted operating surplus (which we define below) that on average is in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both the 12-Quarter Test and the 4-Quarter Test were met. This equates to: (i) 100% of all distributions on the outstanding Class A and common units up to the First Target Distribution plus (ii) 117.65% of any distributions in excess of the First Target Distribution up to $0.59 (the “Second Target Distribution”) plus (iii) 133.33% of any distributions in excess of the Second Target Distribution; and

 

Ø   we do not reduce the amount distributed per unit for any such 12 quarters;

The second test is the 4-Quarter Test, which requires that for each of (i) the last four full, consecutive, non-overlapping calendar quarters in the Incentive Trigger Period, or (ii) any four full, consecutive and non-overlapping quarters occurring after such last four quarters in the Incentive Trigger Period, provided that we have paid at least the IQD in each calendar quarter occurring between the end of the Incentive Trigger Period and the beginning of the four full, consecutive and non-overlapping quarters that satisfy the 4-Quarter Test, or (iii) any four full, consecutive and non-overlapping quarters occurring partially within and partially after such last four quarters of the Incentive Trigger Period:

 

Ø   we pay cash distributions from operating surplus to the holders of our outstanding Class A and common units that exceed the First Target Distribution on all of the outstanding Class A and common units;

 

Ø   we generate adjusted operating surplus during each quarter in an amount at least equal to all cash distributions on the outstanding Class A and common units plus the amount of any management incentive distributions that would have been payable if both tests were met. This equates to (i) 100% of all distributions on the outstanding Class A and common units up to the First Target Distribution plus (ii) 117.65% of any distributions in excess of the First Target Distribution up to the Second Target Distribution plus (iii) 133.33% of any distributions in excess of the Second Target Distribution; and

 

Ø   we do not reduce the amount distributed per unit with respect to any of such four quarters.

If both the 12-Quarter Test and 4-Quarter Test have been met, then:

 

Ø   We will make a one-time management incentive distribution to the holder of our management incentive interests (contemporaneously with the distribution paid with respect to the Class A and common units for the last calendar quarter in the 4-Quarter Test) equal to the cumulative amount of the management incentive distributions that would have been paid based on the level of distributions

 


 

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made on our Class A and common units during the Incentive Trigger Period if the management incentive distributions were payable on a quarterly basis rather than after completion of the Incentive Trigger Period, that is, (x) 17.65% of the sum of any cumulative amounts by which quarterly cash distributions per unit paid on the outstanding Class A and common units during the Incentive Trigger Period exceeded the First Target Distribution up to the Second Target Distribution and (y) 33.33% of the sum of any cumulative amounts by which quarterly cash distributions per unit paid on the outstanding Class A and common units during the Incentive Trigger Period exceeded the Second Target Distribution.

 

Ø   For each calendar quarter after the two tests are satisfied, the holders of our Class A units, common units and management incentive interests will receive:

 

  Ø   2%, 83% and 15%, respectively, of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the First Target Distribution up to the Second Target Distribution; and

 

  Ø   2%, 73% and 25%, respectively, of cash distributions from available cash from operating surplus that we pay for the quarter in excess of the Second Target Distribution.

Our board of directors has adopted a policy that it will raise our quarterly cash distribution only when it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such increased distribution level for a sustained period. While this is our current policy, our board of directors may alter the policy in the future when and if it determines such alteration to be appropriate. There is no cap on the distributions we may make on the management incentive interests.

Definition of adjusted operating surplus

Adjusted operating surplus generally means, for any period:

 

Ø   operating surplus generated with respect to that period; less

 

Ø   any net increase in working capital borrowings with respect to that period; less

 

Ø   any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

 

Ø   any net decrease in working capital borrowings with respect to that period; plus

 

Ø   any net increase in cash reserves for operating expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium.

Adjusted operating surplus is intended to reflect the cash generated from our operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods.

 


 

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PERCENTAGE ALLOCATIONS OF AVAILABLE CASH FROM OPERATING SURPLUS

The following table illustrates the percentage allocations of the available cash from operating surplus between the unitholders and the owner of our management incentive interests up to various distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our Class A unitholders and common unitholders and the holders of our management incentive interests in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Quarterly distribution level,” until available cash from operating surplus we distribute reaches the next distribution level, if any. The percentage interests shown for the IQD are also applicable to quarterly distribution amounts that are less than the IQD. The percentage interests shown in the table below assume that the Class A units have not been converted into common units as described herein.

 

          Marginal percentage interest in
distributions
 
     

Quarterly
distribution

level

   Class A
unitholders
    Common
unitholders
    Management
incentive
interests
 

IQD

   $0.42    2 %   98 %   0 %

First Target Distribution

   up to $0.48    2 %   98 %   0 %

Second Target Distribution*

   above $0.48
up to $0.59
   2 %   83 %   15 %

After that*

   above $0.59    2 %   73 %   25 %

*   Assumes the 12-Quarter Test and the 4-Quarter Test have been met. Until the 12-Quarter Test and the 4-Quarter Test are met and distributions with respect to the management incentive interests become payable, quarterly distributions in excess of the First Target Distribution will be made 2% to the holder of the Class A units and 98% to the holders of common units, pro rata.

DISTRIBUTIONS FROM CAPITAL SURPLUS

How we will make distributions from capital surplus

We will make distributions of available cash from capital surplus, if any, in the following manner:

 

Ø   First, 2% to the holder of our Class A units and 98% to all common unitholders, pro rata, until we distribute for each common unit that was issued in this offering an amount of available cash from capital surplus equal to the initial public offering price; and

 

Ø   After that, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Effect of a distribution from capital surplus

Our limited liability company agreement treats a distribution of capital surplus as the repayment of the initial common unit price from this initial public offering, which is a return of capital. We refer to the initial public offering price less any distributions of capital surplus per common unit as the “unrecovered initial common unit price.” Each time we make a distribution of capital surplus, the IQD, the First Target Distribution and the Second Target Distribution will be reduced in the same proportion as the corresponding reduction in the unrecovered initial common unit price. Because distributions of capital surplus will reduce the IQD, after we make any of these distributions, it may be easier for our manager to receive management incentive distributions. However, any distribution of capital surplus before the unrecovered initial common unit price is reduced to zero cannot be applied to the payment of the IQD.

 


 

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Once we distribute capital surplus on a common unit issued in this offering in an amount equal to the initial common unit price, we will reduce the IQD, the First Target Distribution and the Second Target Distribution to zero. We will then make all future distributions from operating surplus, with 2% being distributed to the holder of our Class A units, 73% being distributed to our common unitholders, pro rata, and 25% being distributed to the holder of our management incentive interests. The percentage interests shown above for the Class A units assume they have not been converted into common units. If the Class A units have been converted, the common units will receive the 2% of distributions originally allocated to the Class A units.

Adjustment to the IQD and target distribution levels

In addition to adjusting the IQD, First Target Distribution and Second Target Distribution to reflect a distribution of capital surplus, if we combine our common units into fewer common units or subdivide our common units into a greater number of common units, we will proportionately adjust:

 

Ø   the IQD;

 

Ø   the First Target Distribution and Second Target Distribution; and

 

Ø   the unrecovered initial common unit price.

For example, if a two-for-one split of the common units should occur, the First Target Distribution, the Second Target Distribution and the unrecovered initial common unit price would each be reduced to 50% of its initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the IQD, the First Target Distribution and the Second Target Distribution for each quarter by multiplying each by a fraction, the numerator of which is available cash for that quarter (after deducting our board of directors’ estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus our board of directors’ estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, we will account for the difference in subsequent quarters.

DISTRIBUTIONS OF CASH UPON LIQUIDATION

General

If we dissolve in accordance with our limited liability company agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and our manager in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Manner of adjustments for gain

The manner of the adjustment for gain is set forth in our limited liability company agreement, and requires that we will allocate any gain to the unitholders and holders of the Class A units in the following manner:

 

Ø   First, to the holders of common units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 


 

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Ø   Second, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

 

  (1)   the unrecovered initial common unit price; and

 

  (2)   the amount of the IQD for the quarter during which our liquidation occurs; and

 

Ø   Third, 2% to the holder of our Class A units and 98% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

 

  (1)   the amount described above under the second bullet point of this paragraph; and

 

  (2)   the excess of (I) over (II), where

 

  (I)   equals the sum of the excess of the First Target Distribution per common unit over the IQD for each quarter of our existence; and

 

  (II)   equals the cumulative amount per common unit of any distributions of available cash from operating surplus in excess of the IQD per common unit that we distributed 98% to our common unitholders, pro rata, for each quarter of our existence; and

 

Ø   Fourth, 2% to the holder of our Class A units, 83% to the common unitholders, pro rata, and 15% to the holder of our management incentive interests until the capital account for each common unit is equal to the sum of:

 

  (1)   the amount described above under the second bullet point of this paragraph; and

 

  (2)   the excess of (I) over (II), where

 

  (I)   equals the sum of the excess of the Second Target Distribution per common unit over the First Target Distribution for each quarter of our existence; and

 

  (II)   equals the cumulative amount per common unit of any distributions of available cash from operating surplus in excess of the First Target Distribution per common unit that we distributed 83% to our common unitholders, pro rata, for each quarter of our existence; and

 

Ø   After that, 2% to the holder of our Class A units, 73% to all common unitholders, pro rata, and 25% to the holder of our management incentive interests.

Manner of adjustments for losses

Upon our liquidation, we will generally allocate any loss 2% to the holder of the Class A units and 98% to the holders of the outstanding common units, pro rata.

Adjustments to capital accounts

We will make adjustments to capital accounts upon the issuance of additional common units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the holder of the Class A units, the common unitholders, and the holders of the management incentive interests in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional common units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional common units or upon our liquidation in a manner which results, to the extent possible, in the capital account balances of the holders of the management incentive interests equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 


 

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Cash distribution policy and restrictions on distributions

You should read the following discussion of our cash distribution policy in conjunction with specific assumptions included in this section. For more detailed information regarding the factors and assumptions upon which our cash distribution policy is based, please read “—Estimated EBITDA” below. In addition, you should read “Cautionary note regarding forward-looking statements” and “Risk factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

For additional information regarding our historical and pro forma results of operations, you should refer to our historical and pro forma consolidated financial statements for the fiscal year ended September 30, 2005, the three months ended December 31, 2005 and the nine months ended September 30, 2006, included elsewhere in this prospectus as well as “Management’s discussion and analysis of financial condition and results of operations.”

GENERAL

Rationale for our cash distribution policy

Our cash distribution policy reflects a basic judgment that our unitholders will be better served by our distributing our available cash rather than our retaining it. It is the current policy of our board of directors that we should increase our level of quarterly cash distributions per unit only when, in its judgment, it believes that (i) we have sufficient reserves and liquidity for the proper conduct of our business, including the maintenance of our asset base, and (ii) we can maintain such an increased distribution level for a sustained period. The amount of available cash will be determined by our board of directors for each calendar quarter after the closing of the offering and will be based upon recommendations from our management. Because we believe we will generally finance any expansion capital expenditures and investment capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. In addition, since we are not subject to an entity-level federal income tax, we have more cash to distribute to you than would be the case if we were subject to federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash quarterly. We are a recently formed limited liability company and have not made any cash distributions. For a more detailed discussion, please read “How we make cash distributions” elsewhere in this prospectus.

Restrictions and limitations on our ability to make quarterly distributions

We cannot guarantee that unitholders will receive quarterly cash distributions from us or that we can or will maintain any increases in our quarterly cash distributions. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

 

Ø   Other than the obligation under our limited liability company agreement to distribute available cash on a quarterly basis, which is subject to our board of directors’ authority to establish reserves and other limitations, our unitholders have no contractual or other legal right to receive distributions.

 

Ø   Our board of directors will have broad discretion to establish reserves for the prudent conduct of our business and for future cash distributions, including, during the Incentive Trigger Period, reserves related to the potential payment of the one-time management incentive distribution with respect to the Incentive Trigger Period, and the establishment of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy.

 


 

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Ø   Our ability to make distributions of available cash will depend primarily on our cash flow from operations, which will fluctuate from quarter to quarter primarily based on commodity prices, production volumes, investor funds raised and the number of wells we drill. Although our limited liability company agreement provides for quarterly distributions of available cash, we have no prior history of making distributions to our members.

 

Ø   We anticipate that we will be subject to restrictions on distributions under our proposed credit agreement, including customary financial covenants. Should we be unable to satisfy these restrictions or another default or event of default occurs under our credit agreement, we anticipate we would be prohibited from making a distribution to you notwithstanding our stated distribution policy.

 

Ø   Even if we do not modify our cash distribution policy, the amount of distributions we pay and the decision to make any distribution will be determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

Ø   We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including the amount of natural gas and oil we produce, the price at which we sell our natural gas and oil, the level of our operating costs, our ability to acquire, locate and produce new reserves, results of our hedging activities, the number of wells we drill, the amount of funds we raise through our investment partnerships, the level of our interest expense and the level of our capital expenditures. See “Risk factors” for information regarding these factors.

 

Ø   Although our limited liability company agreement requires us to distribute our available cash, our limited liability company agreement may be amended with the approval of our board of directors and a majority of our outstanding units, voting as a single class. At the closing of this offering, Atlas America and its affiliates will own approximately 83.0% of the outstanding units (approximately 80.4% if the underwriters exercise their option to purchase additional common units in full) and will have the ability to amend our limited liability company agreement with the approval of our board of directors.

Our ability to make distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, the provisions of existing and future indebtedness, applicable state limited liability company laws and other laws and regulations, including state laws and policies.

Our cash distribution policy limits our ability to grow

Because we distribute our available cash, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. If we issue additional common units or incur debt to fund acquisitions and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units.

Our ability to grow is dependent on our ability to access external expansion capital

Because we expect that we will distribute our available cash from operations to our unitholders each quarter in accordance with the terms of our limited liability company agreement, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund any expansion and investment capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow our capital asset base.

 


 

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OUR INITIAL QUARTERLY DISTRIBUTION RATE

Our cash distribution policy

Upon completion of this offering, our board of directors will adopt a cash distribution policy pursuant to which we will pay an IQD of $0.42 per common unit and Class A unit for each complete quarter. Beginning with the quarter ending December 31, 2006, we will pay our quarterly distribution within 45 days after the end of each quarter ending March, June, September and December to holders of record on the record date established for the distribution. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. In February 2007, we expect to pay a distribution to our unitholders equal to the IQD prorated for the portion of the quarter ending December 31, 2006 that we are public. These distributions will not be cumulative. Consequently, if we do not pay distributions on our common units and Class A units with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

If the underwriters exercise their option to purchase additional common units from us, we will use the additional net proceeds from such exercise to redeem from Atlas America an equal number of common units. Accordingly, the exercise of the underwriters’ option will not affect the total amount of units outstanding or the amount of cash needed to pay the IQD rate on all units. Our ability to make cash distributions at the IQD rate pursuant to this policy will be subject to the factors described above under the caption “—Restrictions and limitations on our ability to make quarterly distributions.”

The following table sets forth the assumed number of outstanding common and Class A units upon the closing of this offering and the estimated aggregate amount of available cash from operating surplus, which we also refer to as cash available for distributions, we need to pay the IQD on such units for one full quarter (at the initial rate of $0.42 per unit per quarter) and for four full quarters (at the initial rate of $1.68 per unit on an annualized basis):

 

          Initial quarterly distribution
      Number of
units
   One quarter    Four quarters

Common units

   36,674,365    $ 15,403,233    $ 61,612,933

Class A units

   748,456      314,352      1,257,406
                  

Total

   37,422,821    $ 15,717,585    $ 62,870,339
                  

The Class A units will be entitled to 2% of all distributions that we make prior to our liquidation. The 2% sharing ratio of the Class A units will not be reduced if we issue additional equity securities in the future.

We do not have a legal obligation to pay distributions at our IQD rate or at any other rate. Our limited liability company agreement requires that we distribute all of our available cash quarterly. Available cash is defined to generally mean, for each fiscal quarter, cash generated from our business in excess of the amount our board of directors determines is necessary or appropriate to provide for the conduct of our business, to comply with applicable law, any of our debt instruments or other agreements or to provide for payment of the one-time management incentive distribution for the Incentive Trigger Period or for future distributions to our unitholders for any one or more of the upcoming four quarters.

 


 

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In the sections that follow, we present in detail the basis for our belief that we will have sufficient available cash from operating surplus to pay the IQD on all outstanding common units and Class A units for each full calendar quarter through December 31, 2007. In those sections, we present the following two tables:

 

Ø   “Estimated cash available for distribution,” in which we present our estimated EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the IQD rate on all the outstanding common units and Class A units for each quarter for the twelve months ending December 31, 2007. In the footnotes to this table, we present the significant assumptions and considerations underlying our belief that we will generate this estimated EBITDA.

 

Ø   “Unaudited pro forma cash available for distribution,” in which we present the amount of pro forma available cash we would have had available for distribution to our unitholders in the twelve months ended December 31, 2005 and September 30, 2006, based on our pro forma financial statements included elsewhere in this prospectus. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

FINANCIAL FORECAST

We do not as a matter of course make public projections of financial information. Our forecast information below presents, to our best knowledge and belief, our expected results of operations and cash flows for the twelve-month period ending December 31, 2007. Our forecast financial information reflects our judgment as of the date of this prospectus of conditions we expect to exist and the course of action we expect to take during the twelve months ending December 31, 2007. The assumptions disclosed in the footnotes to the table under the caption “—Estimated cash available for distribution—Estimated EBITDA” below are those that we believe are significant to our forecasted information, but we cannot assure you that our forecast results will be achieved. There will likely be differences between our forecast and actual results, and those differences could be material. If we do not achieve the forecast, we may not be able to pay the full IQD or any distribution amount on our outstanding units.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this prospectus and together with “Management’s discussion and analysis of financial condition and results of operations” and “Cautionary note regarding forward-looking statements.” In the view of our management, however, such information was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions and considerations on which we base our belief that we can generate the estimated EBITDA necessary for us to have sufficient available cash for distribution on the common units and Class A units at the IQD rate. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

Neither our independent registered public accounting firm, nor any other independent accountants, have compiled, examined or performed any procedures with respect to the prospective financial information contained in this section, nor have they expressed any opinion or any other form of assurance on such information or its achievability, and they assume no responsibility for, and disclaim any association with, the prospective financial information. The independent registered public accounting firm’s reports included elsewhere in this prospectus relate to the appropriately described historical financial information contained in this section. These reports do not extend to the tables and related information

 


 

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contained in this section and should not be read to do so. In addition, we did not prepare the forecasted financial information:

 

Ø   with a view toward compliance with published guidelines of the SEC or the guidelines established by the American Institute of Certified Public Accountants for preparation and presentation of prospective financial information;

 

Ø   in accordance with GAAP; or

 

Ø   in accordance with procedures applied under the auditing standards of the Public Company Accounting Oversight Board (United States).

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date in this prospectus. Therefore, you should not place undue reliance on this information.

As a result of the factors described in “—Estimated Cash Available for Distribution” and in the footnotes to the table in that section, we believe we will be able to pay distributions at the IQD rate of $0.42 per unit on all outstanding common units and Class A units for each full calendar quarter in the twelve-month period ending December 31, 2007.

ESTIMATED CASH AVAILABLE FOR DISTRIBUTION

In order to pay the IQD to our unitholders of $0.42 per unit per quarter for the twelve month period ending December 31, 2007, our available cash for distribution must be at least approximately $62.9 million over that period. We estimate that our minimum EBITDA for the twelve-month period ending December 31, 2007 must be at least $99.4 million in order to generate cash available for distribution to the holders of our common units and Class A units of approximately $62.9 million over that period. We believe we will generate estimated EBITDA of $105.8 million for the twelve months ending December 31, 2007. We refer to this amount as “Estimated EBITDA.” EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance calculated in accordance with GAAP, as those items are used to measure our operating performance, liquidity or ability to service debt obligations. If our estimate is not achieved, we may not be able to pay the minimum quarterly distribution on all our units. We can give you no assurance that our assumptions will be realized or that we will generate the $99.4 million in minimum EBITDA required to pay the minimum quarterly distribution on all our common units and Class A units. There will likely be differences between our estimates and the actual results we will achieve and those differences could be material.

EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any reserves by our board of directors) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating operating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. EBITDA means the sum of net income (loss) plus:

 

Ø   interest (income) expense;

 

Ø   tax expense; and

 

Ø   depreciation, depletion and amortization.

In calculating the estimated cash available for distribution for the twelve month period ending December 31, 2007, we have included amounts for estimated maintenance and investment capital expenditures, as well as average borrowings of $23.0 million for the period to fund a portion of

investment capital expenditures. If we do not finance such expenditures with borrowings or issuances of

 


 

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additional common units, we would experience a shortfall in the amount of cash generated from our operations to pay both the aggregate cash distributions on our common units and Class A units and

make the investment capital expenditures we expect to make. Our estimated maintenance, expansion and investment capital expenditures are as follows:

 

Ø   Maintenance capital expenditures are capital expenditures that we expect to make on an ongoing basis to maintain our capital asset base at a steady level over the long term. Examples of maintenance capital expenditures include plugging and abandonment costs and capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from our producing properties.

 

Ø   Expansion capital expenditures are those capital expenditures that we expect to make to expand our capital asset base for the longer than short term. The expenditures would include amounts expended to increase the rate of development and production of our existing properties at a rate in excess of that necessary to offset our expected depletion rate decline of existing producing properties and which excess production or operating capacity we expect to extend for longer than the short term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interests, to the extent such expenditures are incurred to increase our capital asset base. For the twelve months ending December 31, 2007, we have not estimated any expansion capital expenditures.

 

Ø   Investment capital expenditures are capital expenditures that are neither maintenance nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Our estimated investment capital expenditures for the twelve months ending December 31, 2007 consist of capital expenditures we expect to make to drill and complete additional development wells in excess of the level of such operations that are necessary to offset our expected depletion rate of our producing properties and replace reserves.

ESTIMATED EBITDA

You should read the information in the footnotes under the caption “—Estimated Cash Available for Distribution” for a discussion of the material assumptions underlying our belief that we will be able to generate Estimated EBITDA of approximately $105.8 million. Our belief is based on those assumptions and reflects our judgment, as of the date of this prospectus, regarding the conditions we expect to exist and the course of action we expect to take over the twelve month period ending December 31, 2007. The assumptions we disclose below are those that we believe are significant to our ability to generate our Estimated EBITDA. If our estimates prove to be materially incorrect, we may not be able to pay the IQD or any amount on our outstanding common units and Class A units during the four calendar quarters ending December 31, 2007.

As shown in the table below, we have also determined that if we achieve the Estimated EBITDA, we would be permitted under the terms of our credit facility to make distributions to our unitholders. In addition, we will be permitted to make distributions at the IQD rate under our credit facility. Our proposed credit facility will limit our ability to pay distributions to the extent we are not in compliance with its terms.

When considering our Estimated EBITDA, you should keep in mind the risk factors and other cautionary statements under the heading “Risk factors” and elsewhere in this prospectus. Any of these risk factors

 


 

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or the other risks discussed in this prospectus could cause our financial condition and results of operations to vary significantly from those set forth in the table below.

The following table illustrates (i) our Estimated EBITDA that we expect to generate for the twelve months ending December 31, 2007 based on the assumptions and considerations described in the footnotes to the table and (ii) the estimated cash available to pay distributions for the twelve-month period ending December 31, 2007, assuming that the offering was consummated on January 1, 2007. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending December 31, 2007 in the table and footnotes are estimates.

Estimated cash available for distribution

 

     

Twelve months ending

December 31, 2007

 
     (in thousands, except per
unit data and ratios)
 

Estimated EBITDA(a)

   $ 105,752  

Less:

  

Cash interest expense(b)

     (2,384 )

Estimated maintenance capital expenditures(c)

     (35,000 )

Investment capital expenditures(d)

     (43,430 )

Plus:

  

Borrowings and other sources for investment capital expenditures(e)

     43,430  

Non-cash compensation expense(f)

     812  
        

Estimated cash available for distribution

   $ 69,180  
        

Expected cash distributions

  

Annualized IQD per unit(g)

   $ 1.68  
        

Distributions to our common unitholders

   $ 61,613  

Distributions to our Class A unitholder

     1,257  
        

Total distributions to our unitholders(g)

   $ 62,870  

Excess of cash available for distribution over minimum annual distributions

     6,310  
        
   $ 69,180  
        

Calculation of minimum estimated EBITDA necessary to pay minimum annual cash distributions:

  

Estimated EBITDA

   $ 105,752  

Less:

  

Excess of cash available for distributions over minimum annual distributions

     6,310  
        

Minimum estimated EBITDA necessary to pay minimum annual cash distributions

   $ 99,442  
        

Debt covenant ratios

  

Funded debt/EBITDA ratio(h)

     0.2x  

Interest coverage ratio(h)

     44.4x  

Current ratio(h)

     1.3x  

 


 

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(a)   As reflected in the table below, to generate our Estimated EBITDA for the twelve months ending December 31, 2007, we have assumed the following regarding our operations, revenues and expenses:

 

Gas and oil production key assumptions:

  

Net natural gas production volume(1)

   9,621,549 Mcf  

Average natural gas price on hedged volumes(2)

   $9.88 per Mcf  

Average natural gas price on unhedged volumes(2)

   $8.84 per Mcf  

Percentage of net gas production assumed to be hedged

   77 %

Net crude oil production volume(1)

   136,211 Bbls  

Average crude oil price(2)

   $63.32 per Bbl  

Partnership management key assumptions:

  

Well construction and completion cost mark-up(3)

   15 %

Administration and oversight(3)

   $15,000 per well  

Administration and oversight(3)

   $75 per well per month  

Gross well services fee range(3)

   $100 –$457 per well per month  

Estimated EBITDA (in thousands):

  

Gas and oil production segment margin

   $  76,815  

Partnership management segment margin

   51,163  
      

Total segment margin(4)

   $127,978  

General and administrative expense(5)

   (22,999 )

Other

   773  
      

Estimated EBITDA

   $  105,752  
      

 

  (1)   Our forecasted natural gas and oil production volumes, net to our equity interest in the production of our investment partnerships and including our direct interests in producing wells, for the twelve months ending December 31, 2007 assumes that currently producing wells will produce at the rates forecasted in our March 31, 2006 reserve report. Also includes new production from an estimated 837 additional gas and oil wells we project to be connected during the twelve months ending December 31, 2007, which we intend to drill on behalf of our investment partnerships and assume will produce at rates consistent with wells of similar characteristics contained in our March 31, 2006 reserve report. Additionally, we have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, we have assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which we primarily depend on Atlas Pipeline to complete. The following table outlines historical and estimated natural gas and oil production volumes, net to our equity interest in the production of our investment partnerships and including our direct interests in producing wells:

 

      Natural gas
production
(Mcf per day)
   Oil
production
(Bbl per day)
   Overall
production
(Mcfe per day)

Twelve months ended September 30, 2006

   23,410    419    25,924

Twelve months ending December 31, 2007

   26,360    373    28,598

 

  (2)   Our weighted average net natural gas sales price of $9.65 per Mcf is calculated by taking into account the fact that we have hedged 7,433,647 Mcf (or approximately 77% of our forecasted gas production volume for the twelve months ended December 31, 2007) at a weighted average natural gas sales price of approximately $9.88 per Mcf, and have unhedged production volumes (2,187,902 Mcf) at an assumed price of $8.84 per Mcf, which is based on the twelve month NYMEX strip at November 10, 2006 for the twelve months ending December 31, 2007.

 


 

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We have assumed that all of our crude oil production will be sold at spot market prices. Our average natural gas prices for both hedged and unhedged volumes include a positive basis differential and Btu adjustment of $0.69. The following table indicates the commodity prices we expect to receive, inclusive of all basis differential and Btu adjustments.

 

      Overall
natural gas
prices per
Mcf
(inclusive
of hedging)
   Natural gas prices
per Mcf
(unhedged portion)
   Oil prices
per Bbl
(spot prices)

Twelve months ending December 31, 2007

   $ 9.65    $ 8.84    $ 63.32

 

  (3)   We have assumed that we will raise approximately $270.0 million through investment partnerships in the twelve-month period ending December 31, 2007 and that our equity interest in such partnerships will be approximately 35%. We have assumed that we will drill 888 gross (821 net) wells on behalf of the partnerships, and for each we will receive a 15% mark-up on the investors’ cost to drill and complete the well and a $15,000 administration and oversight fee. We have assumed that we will, on average, operate approximately 6,400 wells per month on behalf of our partnerships, and receive a gross monthly $75 per well administrative fee and a gross monthly well services fee that ranges from $100 to $457 per well. We expect that our well services profit margin will be approximately 41%.

 

  (4)   We have assumed total segment margin of $128.0 million for the twelve months ending December 31, 2007, as compared to pro forma total segment margin of $115.5 million for the twelve months ended September 30, 2006. The increase in our segment margin is due to anticipated increases in natural gas and oil volumes produced and number of wells drilled and operated.

 

  (5)   We have assumed general and administrative expense of $23.0 million for the twelve months ending December 31, 2007, as compared to $22.0 million of pro forma general and administrative expense for the twelve months ended September 30, 2006. Included in these expenses are $500,000 in costs associated with Schedule K-1 preparation and distribution.

 

(b)   Our estimated cash interest is comprised of the following components:

 

  (i)   Approximately $1.9 million attributable to estimated average borrowings of $23.0 million under our proposed credit facility for the twelve month period ending December 31, 2007 at an estimated interest rate of 8.4% to fund a portion of the $43.4 million of estimated investment capital expenditures. We expect to fund the remaining portion of estimated investment capital expenditures with a portion of estimated funds received from our investment partnerships for the twelve months ending December 31, 2007 which have not yet been applied to the drilling and completion of wells.

 

  (ii)   Approximately $0.5 million of annual commitment fees for the estimated unused portion of our credit facility for the twelve months ending December 31, 2007.

 

(c)   Our limited liability company agreement requires us to deduct from operating surplus each quarter estimated maintenance capital expenditures as opposed to actual maintenance capital expenditures in order to reduce disparities in operating surplus caused by fluctuations in our actual maintenance capital expenditures. Because of the substantial maintenance capital expenditures we are required to make to maintain our asset base, we estimate that our initial annual estimated maintenance capital expenditures for purposes of calculating operating surplus will be approximately $35.0 million per year as described in the next paragraph. Our board of directors, including a majority of our conflicts committee, may determine to adjust the annual amount of our estimated maintenance capital expenditures. In years when estimated maintenance capital expenditures are higher than actual

 


 

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maintenance capital expenditures, the amount of cash available for distribution to unitholders will be lower than if actual maintenance capital expenditures were deducted from operating surplus.

We estimate that our initial annual estimated maintenance capital expenditures will be approximately $35.0 million per year. Our drilling program assumes that we will drill a total of 888 gross (287 net to our interest in the partnerships) wells during the twelve months ending December 31, 2007, of which 366 gross (123 net) wells will constitute maintenance capital projects required to maintain our current production volumes, which comprises $35.0 million of the $78.4 million projected for total capital expenditures. We also have included estimated maintenance capital expenditures of approximately $350,000 per year for potential costs that we may incur for lease renewals and similar expenditures that will enable us to maintain our capital asset base.

 

(d)   Our investment capital expenditures projected for the twelve-month period ending December 31, 2007 of approximately $43.4 million are expected to be incurred to drill 522 gross (164 net to our interest in the partnerships) wells during such period. These newly drilled wells would be in excess of the 366 gross (123 net) wells that we project need to be drilled in the twelve months ending December 31, 2007 to offset the expected production decline rate from our existing producing wells. We expect to fund investment capital expenditures as described in (e) below.

 

(e)   Reflects funding of the $43.4 million of estimated investment capital expenditures for the twelve months ending December 31, 2007 with $23.0 million of estimated average borrowings under our credit facility and a portion of estimated funds received from our investment partnerships for the twelve months ending December 31, 2007 which have not yet been applied to the drilling and completion of wells. In the future, we anticipate that we will continue to utilize these sources of financing to fund investment and expansion capital expenditures. As a result, we do not expect any such capital expenditures to have an immediate impact on available cash for distribution.

 

(f)   Reflects additional expense related to amortization of incentive compensation for our president. Upon the completion of this offering, pursuant to his employment agreement with Atlas America, our president will receive approximately 50,000 restricted common units and options representing a 1% membership interest in us.

 

(g)   The table below sets forth the assumed number of outstanding common units and Class A units upon the closing of this offering and the full IQD payable on the outstanding common units and Class A units for the twelve-month period ending December 31, 2007.

 

      Number of
units
   Estimated
distribution
per unit
   Estimated
annual
distributions

Common units

   36,674,365    $ 1.68    $ 61,612,933

Class A units

   748,456    $ 1.68    $ 1,257,406
              

Total

   37,422,821       $ 62,870,339
              

 

(h)   Our new credit facility will contain financial covenants which will require us to maintain, as of the end of each fiscal quarter, a ratio of funded debt to EBITDA measured for the preceding twelve months, of not more than 3.5 to 1.0; a consolidated interest coverage ratio measured for the preceding twelve months, of not less than 2.5 to 1.0 and a current ratio of not less than 1.0 to 1.0. We would have been in compliance on a pro forma basis with these covenants for the twelve months ended September 30, 2006 and believe we will be in compliance with the funded debt and interest coverage covenants for the twelve months ended December 31, 2007. In addition, a default by us on the payment of any indebtedness in excess of $2.5 million will constitute an event of default under our credit agreement that would prohibit us from making distributions. Our credit facility will permit us to make distributions to our unitholders as long as we are neither in default nor, following such distribution, would be in default.

 


 

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In preparing the estimates above, we have assumed that there will be no material change in the following matters, and thus they will have no impact on our Estimated EBITDA:

 

Ø   There will not be any material expenditures related to new federal, state or local regulations in the areas where we operate.

 

Ø   There will not be any material change in the natural gas industry or in market, regulatory and general economic conditions that would affect our cash flow.

 

Ø   We will not undertake any extraordinary transactions that would materially affect our cash flow.

 

Ø   There will be no material nonperformance or credit-related defaults by suppliers, customers or vendors.

While we believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic regulatory and competitive risks and uncertainties, including those described in “Risk factors,” that could cause actual results to differ materially from those we anticipate. If our assumptions are not realized, the actual available cash that we generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the full IQD or any amount on all our outstanding common units and Class A units with respect to the four calendar quarters ending December 31, 2007 or thereafter, in which event the market price of the common units may decline materially.

SENSITIVITY ANALYSIS

Our ability to generate sufficient cash from our operations to pay distributions to our unitholders of not less than the IQD per unit for the twelve months ending December 31, 2007 is a function of the following primary variables:

 

Ø   the amount of natural gas and oil we produce;

 

Ø   the price at which we sell our natural gas and oil; and

 

Ø   the amount of funds raised from our investment partnerships.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations to pay the IQD on our outstanding units. This sensitivity analysis also assumes that we will be able to identify suitable drilling locations for the number of wells forecasted to be drilled based on the amount of funds raised from our investment partnerships and that we are able to drill that number of wells during the forecast period.

Production volume changes.    For purposes of our estimates set forth above, we have assumed that our net gas production totals 9,621,549 Mcf during the twelve months ending December 31, 2007. If our actual net gas production realized during such twelve-month period is 5% more (or 5% less) than such estimate (that is, if actual net realized production is 10,102,626 Mcf or 9,140,471 Mcf), we estimate that our estimated cash available to pay distributions would change by approximately $4.3 million.

Natural gas price changes.    For purposes of our estimates set forth above, we have assumed that our weighted average net realized natural gas sales price for our net production volumes is $9.65 per Mcf. If the average realized natural gas sales price for our net production volumes that are unhedged were to

 


 

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change by $1.00 per Mcf, we estimate that our estimated cash available to pay distributions would change by approximately $2.2 million, assuming no changes in any other variables, and assuming we have hedged approximately 77% of our forecast proved developed production from currently producing wells.

Funds raised changes.    For purposes of our estimates set forth above, we have assumed funds raised from our investment partnerships will total $270.0 million during the twelve months ending December 31, 2007. If actual funds raised during such period are 5% more or less than our estimate, we estimate that our estimated cash available would change by approximately $2.5 million.

UNAUDITED PRO FORMA AVAILABLE CASH FOR DISTRIBUTION

If we had completed the transactions contemplated in this prospectus on January 1, 2005, our pro forma available cash for distribution would have been $14.0 million for the twelve months ended December 31, 2005. This amount would have been insufficient by approximately $48.9 million to pay the IQD rate of $.42 per unit ($1.68 on an annual basis) on our outstanding common units and Class A units.

If we had completed the transactions contemplated in this prospectus on October 1, 2005, our pro forma available cash for distribution would have been $22.4 million for the twelve months ended September 30, 2006. This amount would have been insufficient by approximately $40.5 million to pay the IQD rate of $0.42 per unit ($1.68 on an annualized basis) on our outstanding common units and Class A units.

Pro forma cash available for distributions excludes any cash from working capital or other borrowings. As described in “How we make cash distributions—Operating Surplus and Capital Surplus,” we may also use cash from these sources for distributions. Pursuant to the terms of our limited liability company agreement, our board of directors would have had the discretionary authority to cause us to borrow funds under our proposed credit facility to make up some or all of this estimated shortfall.

The following table illustrates, on a pro forma basis for the twelve months ended December 31, 2005 and September 30, 2006, cash available to pay distributions, assuming that this offering and the related transactions had been consummated on January 1, 2005 and October 1, 2005, respectively.

The pro forma financial statements, from which pro forma available cash is derived, do not purport to present our results of operations had the transactions contemplated above actually been completed as of the dates indicated. Furthermore, available cash is a cash accounting concept, while our pro forma financial statements have been prepared on an accrual basis. We derived the amounts of pro forma available cash stated above in the manner described in the table below. As a result, the amount of pro forma available cash should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed and completed the transactions contemplated below in earlier periods.

 


 

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Unaudited pro forma available cash for distribution

 

       Pro forma  
       

Twelve

months ended
December 31, 2005

   

Twelve

months ended

September 30, 2006

 
       (in thousands, except per unit data and ratios)  

Pro forma net income before taxes(a)

     $ 62,839 (b)   $ 70,432  

Plus:

      

Interest expense

       1,249       1,651  

Depreciation, depletion and amortization

       15,812       21,227  
                  

EBITDA(c)

       79,900       93,310  

Less:

      

Pro forma cash interest expense(d)

       (749 )     (1,151 )

Pro forma incremental expense of being a public limited liability company(e)

       (500 )     (500 )

Capital expenditures(f)

       (64,644 )     (69,287 )
                  

Pro forma available cash

     $ 14,007     $ 22,372  
                  

Cash distributions:(g)

      

Expected distribution per unit

     $ 1.68     $ 1.68  
                  

Distributions to our common unitholders

     $ 61,613     $ 61,613  

Distributions to our Class A unitholder

       1,257       1,257  
                  

Cash necessary to pay the IQD to our Class A and common unitholders

     $ 62,870     $ 62,870  
                  

Shortfall

     $ (48,863 )   $ (40,498 )
                  

Debt covenant ratios

      

Funded debt/EBITDA(h)

       0.1x       0.2x  

Interest coverage ratio(h)

       83.9x       61.2x  

Current ratio(h)

       1.8x       1.6x  

(a)   Excludes any adjustment for estimated incremental expenses of being a publicly-traded limited liability company, including Schedule K-1 preparation and distribution. All other public company expenses are included in our historical general and administrative expense.

 

(b)   The following table reconciles pro forma income before taxes for the twelve months ended December 31, 2005:

 

Pro forma income before taxes for the year ended September 30, 2005

   $ 56,828  

Pro forma income before taxes for the three months ended December 31, 2005

     19,735  

Pro forma income before taxes for the three months ended December 31, 2004

     (13,724 )
        

Pro forma income before taxes for the twelve months ended December 31, 2005

   $ 62,839  
        

 

(c)   EBITDA represents net income before net interest expense, income taxes, and depreciation, depletion and amortization. EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of EBITDA is relevant and useful because it helps our investors to understand our operating performance and makes it

 


 

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easier to compare our results with other companies that have different financing and capital structures or tax rates. EBITDA should not be considered in isolation of, or as a substitute for, net income as an indicator of operating performance or cash flows from operating activities as a measure of liquidity.

(d)   Reflects an increase from historical interest expense, excluding amortization of deferred financing costs, as a result of interest expense principally related to average borrowings under Atlas America’s credit facility.
(e)   Gives effect to $500,000 in annual incremental general and administrative expenses we estimate we would incur associated with our Schedule K-1 preparation and distribution.
(f)   Gives effect to the capital expenditures for the drilling and completion of new wells and wells that were in the process of being drilled. It also gives effect to other capital expenditures such as facilities and other support equipment. During the twelve months ended December 31, 2005, we drilled and completed 699 gross (230 net) wells. During the twelve months ended September 30, 2006, we drilled and completed 697 gross (235 net) wells. During such periods, we did not characterize capital expenditures as maintenance, investment or expansion and did not plan capital expenditures in a manner intended to maintain or expand our production or asset base. As a result, we have not attempted to characterize the pro forma capital expenditures reflected here as maintenance, investment or expansion.
(g)   The table below sets forth the assumed number of outstanding common units and Class A units upon the closing of this offering and the full IQD payable on them for the twelve month period ending December 31, 2007:

 

      Number of
units
   Estimated
distribution
per unit
   Estimated
annual
distributions

Common units

   36,674,365    $ 1.68    $ 61,612,933

Class A units

   748,456    $ 1.68      1,257,406
              

Total

   37,422,821       $ 62,870,339
              

 

(h)   Our new credit facility will contain financial covenants which would require us to maintain, as of the end of each fiscal quarter, a ratio of funded debt to EBITDA measured for the preceding twelve months, of not more than 3.5 to 1.0; a consolidated interest coverage ratio measured for the preceding twelve months, of not less than 2.5 to 1.0 and a current ratio of not less than 1.0 to 1.0. We would have been in compliance on a pro forma basis with these covenants for the twelve months ended December 31, 2005 and September 30, 2006. In addition, a default by us on the payment of any indebtedness in excess of $2.5 million will constitute an event of default under our credit agreement that would prohibit us from making distributions. Our credit facility will permit us to make distributions to our unitholders as long as we are neither in default nor, following such distribution, would not be in default.

 


 

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Selected historical financial data

The following table sets forth selected historical combined financial and operating data for our predecessor, Atlas America E & P Operations, as of and for the periods indicated. Atlas America E & P Operations are the subsidiaries of Atlas America which hold its natural gas and oil development and production assets and liabilities, substantially all of which Atlas America will transfer to us upon the completion of this offering. We derived the historical financial data as of September 30, 2004 and 2005 and December 31, 2005 and for the years ended September 30, 2003, 2004 and 2005 and the three months ended December 31, 2005 from Atlas America E & P Operations’ financial statements, which were audited by Grant Thornton LLP, independent registered public accounting firm, and are included in this prospectus. We derived the historical financial data as of September 30, 2001, 2002 and 2003 and as of December 31, 2004 and for the years ended September 30, 2001 and 2002 from Atlas America E&P Operations’ unaudited financial statements, which are not included in this prospectus. We derived the historical financial data for the three months ended December 31, 2004 and the nine months ended September 30, 2005 and 2006 and the balance sheet information as of September 30, 2006 from Atlas America E & P Operations’ unaudited financial statements included in this prospectus.

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

The following table includes the non-GAAP financial measure of EBITDA. For a definition of EBITDA and a reconciliation to its most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Prospectus summary—Non-GAAP Financial Measures.”

 


 

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Years ended September 30,

   

Three months ended

December 31,

    Nine months ended
September 30,
 
     2001     2002     2003     2004     2005         2004             2005            2005           2006     
    (unaudited)                       (unaudited)           (unaudited)  
          (in thousands)        

Income statement data:

                 

Revenues:

                 

Gas and oil production

  $ 36,681     $ 28,916     $ 38,639     $ 48,526     $ 63,499     $ 14,659     $ 24,086     $ 48,840     $ 66,696  

Partnership management:

                 

Well construction and completion

    43,464       55,736       52,879       86,880       134,338       30,558       42,145       103,780       135,329  

Administration and oversight

    3,632       4,805       5,090       8,396       9,590       2,156       2,964       7,436       8,487  

Well services

    7,403       7,585       7,635       8,430       9,552       2,248       2,561       7,304       9,498  

Gathering(1)

    3,448       3,497       3,898       4,191       4,359       1,158       1,407       3,200       6,902  
                                                                       

Total revenues

    94,628       100,539       108,141       156,423       221,338       50,779       73,163       170,560       226,912  

Expenses:

                 

Gas and oil production and exploration(1)

    7,832       8,264       8,486       8,838       9,070       1,802       2,458       7,268       12,506  

Partnership management:

                 

Well construction and completion

    36,602       48,443       45,982       75,548       116,816       26,573       36,648       90,243       117,677  

Well services

    2,960       3,747       3,773       4,398       5,167       1,191       1,487       3,976       5,540  

Gathering(1)

    103       48       29       53       52       21       38       31       159  

Gathering fee – Atlas Pipeline(1)

    13,140       10,756       14,564       17,189       21,929       5,281       7,930       16,649       22,719  

General and administrative

    10,912       9,045       8,390       10,159       12,297       2,147       5,801       10,151       15,387  

Compensation reimbursement – affiliate

    1,150       1,181       1,400       1,050       602       213       163       389       1,041  

Depreciation, depletion and amortization

    9,594       9,409       9,938       12,064       14,061       3,165       4,916       10,895       16,311  
                                                                       

Total operating expenses

    82,293       90,893       92,562       129,299       179,994       40,393       59,441       139,602       191,340  
                                                                       

Operating income

    12,335       9,646       15,579       27,124       41,344       10,386       13,722       30,958       35,572  

Other income (expenses):

                 

Interest income

    263       686       251       250       317       1       32       316       653  

Other – net

    934       865       107       194       (238 )     1       25       (239 )     309  
                                                                       

Total other income (expenses)

    1,197       1,551       358       444       79       2       57       77       962  
                                                                       

Net income before taxes

  $ 13,532     $ 11,197     $ 15,937     $ 27,568     $ 41,423     $ 10,388     $ 13,779     $ 31,035     $ 36,534  
                                                                       

Cash flow data:

                 

Cash provided by operating activities

  $ 40,764     $ 783     $ 20,365     $ 42,523     $ 65,444     $ 22,399     $ 31,783     $ 43,045     $ 15,186  

Cash used in investing activities

    (24,608 )     (15,943 )     (22,112 )     (32,709 )     (59,050 )     (11,591 )     (17,185 )     (47,459 )     (53,926 )

Cash provided by (used in) financing activities

    (394 )     2,289       34       (14,916 )     (320 )     (35 )     74       (285 )     74,428  

Capital expenditures

    19,105       16,832       22,607       33,252       59,124       11,645       17,187       47,479       54,076  

Other financial information (unaudited):

                 

EBITDA

  $ 23,126     $ 20,606     $ 25,875     $ 39,632     $ 55,484     $ 13,553     $ 18,695     $ 41,930     $ 52,845  

Balance sheet data (at period end):

                 

Total assets

  $ 173,319     $ 161,464     $ 178,451     $ 198,454     $ 270,402     $ 221,296     $ 315,052     $ 270,402     $ 416,417  

Liabilities associated with drilling contracts

    13,770       4,948       22,157       29,375       60,971       52,610       70,514       60,971       76,883  

Advances from affiliates

    53,938       75,602       34,776       30,008       13,897       13,854       4,257       13,897       9,575  

Long-term debt, including current maturities

          160       194       420       81       385       156       81       90  

Total debt

    53,938       75,762       34,970       30,428       13,978       14,239       4,413       13,978       9,665  

Total equity

    80,228       67,398       102,031       109,461       146,142       119,269       154,519       146,143       239,967  

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

 


 

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Management’s discussion and analysis of financial condition and results of operations

The historical financial statements included in this prospectus reflect substantially all the assets, liabilities and operations of various wholly-owned subsidiaries of Atlas America, Inc. to be contributed to us upon the closing of this offering. We refer to these subsidiaries’ assets, liabilities and operations as Atlas America E & P Operations or our predecessor. The following discussion analyzes the financial condition and results of operations of Atlas America E & P Operations. You should read the following discussion of the financial condition and results of operations for Atlas America E & P Operations in conjunction with the historical combined financial statements and notes of Atlas America E & P Operations and the pro forma financial statements for Atlas Energy Resources, LLC included elsewhere in this prospectus. In addition, you should read “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” for information regarding some of the risks inherent in our business.

GENERAL

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

We were formed in 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). We are managed by Atlas Energy Management, Inc., a wholly-owned subsidiary of Atlas America. Through our manager, the Atlas America personnel currently responsible for managing our assets and capital raising will continue to do so on our behalf upon completion of this offering.

As of September 30, 2006, our principal assets consisted generally of:

 

Ø   working interests in 6,415 gross producing gas and oil wells;

 

Ø   overriding royalty interests in 632 gross producing gas and oil wells;

 

Ø   our investment partnership business, which includes equity interests in 91 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

 

Ø   approximately 568,900 gross (516,200 net) acres, primarily in the Appalachian Basin, over half of which, or approximately 308,300 gross (294,800 net) acres, are undeveloped; and

 

Ø   an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres in Tennessee.

In addition, at March 31, 2006, the date of our most recent reserve report, we had proved reserves of 170.9 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells.

For the twelve month period ended September 30, 2006, we produced 25,924 Mcfe/d which includes the proportionate share of production from our investment partnerships as well as our direct interests in producing wells. This resulted in an average proved reserves to production ratio, or average reserve life, of approximately 18 years based on our proved reserves at March 31, 2006. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

 


 

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We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

 

Ø   Gas and oil production.    We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

 

Ø   Partnership management.    As managing general partner of our investment partnerships, we receive the following fees:

 

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

 

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

 

  Ø   Well services.    Each partnership pays us a monthly per well operating fee, currently $100 to $457, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

  Ø   Gathering.    Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.”

Our revenue, cash flow from operations and future growth depend substantially on factors beyond our control, such as economic, political and regulatory developments and competition from other sources of energy. Historically, natural gas and oil prices have been volatile and may fluctuate widely in the future. Sustained periods of low prices for natural gas or oil could materially and adversely affect our financial position, our results of operations, the quantities of natural gas and oil reserves that we can economically produce and our access to capital.

We utilize the successful efforts method of accounting for our natural gas and oil properties. Unproved properties are assessed periodically within specific geographic areas and impairments are charged to expense. Geological and geophysical expenses and delay rentals are charged to expense as incurred. Drilling costs are capitalized, but charged to expense if the well is determined to be unsuccessful. Generally, if a well does not find proved reserves within one year following completion of drilling, the costs of drilling the well are charged to expense.

Higher natural gas and oil prices have led to higher demand for drilling rigs, operating personnel and field supplies and services and have caused increases in the costs of those goods and services. To date, the higher sales prices have more than offset the higher drilling and operating costs.

 


 

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

COMPARABILITY OF FINANCIAL STATEMENTS

The historical financial statements of Atlas America E&P Operations included in this prospectus may not be comparable to our results of operations following this offering for the following reasons:

 

Ø   Historically, pursuant to an agreement with Atlas America, Atlas Pipeline received gathering fees generally equal to 16% of the gas sales price of gas gathered through its system. Each partnership pays us gathering fees generally equal to 10% of the gas sales price. After the closing of this offering, we will pay the amount we receive from the partnerships to Atlas America so that our gathering revenues and expenses within our partnership management segment will net to $0. Atlas America will then remit the full amount due to Atlas Pipeline pursuant to an agreement we will enter into with Atlas America upon the closing of this offering. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense.

 

Ø   Atlas America will retain a small gathering system with no book value, which accounted for the gathering expense in our predecessor’s income statement.

 

Ø   Because Atlas America did not previously allocate debt or interest expense to its subsidiaries, our historical results of operations do not include interest expense. We anticipate we will incur indebtedness after the closing of this offering which will create interest expense.

 

Ø   We will incur additional general and administrative expense estimated to be $500,000 per year for costs associated with Schedule K-1 preparation and distribution.

 

Ø   Atlas Energy Resources’ first fiscal year end will be December 31, 2006, as Atlas America’s Board of Directors approved a change in its year end to December 31 from September 30 in July 2006, in contemplation of this offering.

BUSINESS SEGMENTS

We operate two business segments:

 

Ø   Our gas and oil production segment, which consists of our interests in oil and gas properties.

 

Ø   Our partnership management segment, which consists of well construction and completion, administration and oversight, well services and gathering activities.

Gas and oil production

As of September 30, 2006, we owned interests in 7,047 gross wells, principally in the Appalachian Basin, of which we operated 5,978. On average during the quarter ended September 30, 2006, gross production from our wells was 85.9 Mmcfe/d, or approximately 12.2 Mcfe/d per well. Over the past three fiscal years we have drilled 1,864 gross (616 net) wells, 98% of which were successful in producing natural gas in commercial quantities. In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy, LLC that gives us an exclusive right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres owned by Knox Energy. As of September 30, 2006, we had drilled 114 net wells under this agreement. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

 


 

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Our results of operations for our gas and oil production segment are impacted by increases and decreases in the volume of natural gas that we produce, which we refer to as production volumes. Production volumes

and pipeline capacity utilization rates generally are driven by wellhead production and the number of new wells drilled and connected in our areas of operation and more broadly, by demand for natural gas.

Our results of operations for our gas and oil production segment are also impacted by the prices we receive and the margins we generate. Because of the volatility of the prices for natural gas, as of November 1, 2006 we had financial hedges and physical hedges in place for approximately 77% of our expected production for the twelve months ending December 31, 2007. Therefore, we have substantially reduced our exposure to commodity price movements with respect to those volumes under these types of contractual arrangements for this period. For additional information regarding our hedging activities, please read “—Quantitative and Qualitative Disclosures about Market Risk.”

Partnership management

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. Historically, our fund-raising cycle has been on a calendar year basis. We raised $199.8 million in the twelve months ended September 30, 2006. During the twelve months ended September 30, 2006 our investment partnerships invested $206.5 million in drilling and completing wells, of which we contributed $55.0 million. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its general or managing partner. In addition to providing capital for our drilling activities, our investment partnerships are a source of fee-based revenues which are not directly dependent on natural gas and oil prices. We generally agree to subordinate up to 50% of our share of production revenues to specified returns to the investor partners, typically 10% per year for the first five years of distributions.

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

Our results of operations for our partnership management segment are impacted by increases and decreases in the number of wells that we drill and the number of wells we operate. Well construction activity is generally driven by commodity prices and demand for natural gas and oil. In addition, the level of funds we raise through investment partnerships will affect the number of wells we drill. Investor funds raised will be also depend on commodity prices and tax laws associated with natural gas and oil.

GENERAL TRENDS AND OUTLOOK

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

 


 

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Natural gas supply and outlook.    We believe that current natural gas prices will continue to cause relatively high levels of natural gas-related drilling in the United States as producers seek to increase their level of natural gas production. Although the number of natural gas wells drilled in the United States has increased overall in recent years, a corresponding increase in production has not been realized, primarily as a result of smaller discoveries and the decline in production from existing wells. We believe that an increase in United States drilling activity, additional sources of supply such as liquefied natural gas, and imports of natural gas will be required for the natural gas industry to meet the expected increased demand for, and to compensate for the slowing production of, natural gas in the United States. The areas in which we operate are experiencing significant drilling activity as a result of recent high natural gas prices, new increased drilling for deeper natural gas formations and the implementation of new exploration and production techniques.

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

Impact of inflation.    Inflation in the United States did not have a material impact on our results of operations for the three-year period ended September 30, 2006. It may in the future, however, increase the cost to acquire or replace property, plant and equipment, and may increase the costs of labor and supplies. To the extent permitted by competition and our existing agreements, we have and will continue to pass along increased costs to our investors and customers in the form of higher fees.

RESULTS OF OPERATIONS

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

 

    Years ended September 30,    

Three months ended

December 31,

   

Nine months ended

September 30,

     2003     2004     2005        2004           2005        2005     2006

Production revenues (in thousands):

             

Gas(1)

  $ 34,276     $ 42,532     $ 55,376     $ 12,697     $ 21,851     $ 42,679     $ 59,332

Oil

  $ 4,307     $ 5,947     $ 8,039     $ 1,942     $ 2,227     $ 6,097     $ 7,323
Production volumes:              

Gas (Mcf/d)(1)(2)

    19,087       19,905       20,892       20,286       21,468       21,097       24,064

Oil (Bbls/d)

    438       495       433       447       431       428       415

Total (Mcfe/d)

    21,715       22,875       23,490       22,968       24,054       23,665       26,554

Average sales prices:

             

Gas (per Mcf)(3)

  $ 4.92     $ 5.84     $ 7.26     $ 6.80     $ 11.06     $ 7.41     $ 9.03

Oil (per Bbl)

  $ 26.91     $ 32.85     $ 50.91     $ 47.17     $ 56.13     $ 52.23     $ 64.59

Production costs(4):

             

As a percent of production revenues

    18 %     15 %     13 %     12 %     11 %     13 %     16%

Per Mcfe

  $ 0.85     $ 0.87     $ 0.95     $ 0.83     $ 1.10     $ 0.99     $ 1.45

Depletion per Mcfe

  $ 1.01     $ 1.22     $ 1.42     $ 1.28     $ 2.01     $ 1.47     $ 2.04

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

 

(2)   Production quantities consist of the sum of (i) our proportionate share of production from wells in which we have a direct interest, based on our proportionate net revenue interest in such wells, and

 


 

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

 

(3)   Our average sales price before the effects of financial hedging was $5.08 and $8.10 for fiscal 2003 and nine months ended September 30, 2006, respectively; we did not have any financial hedges in the other periods presented.

 

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

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

 

    Years ended September 30,  

Three months ended

December 31,

 

Nine months ended

September 30,

     2003   2004   2005      2004         2005      2005   2006

Average construction and completion revenue per well

  $ 187   $ 193   $ 218   $ 224   $ 225   $ 217   $ 295

Average construction and completion cost per well

    163     168     190     195     196     188     256
                                         

Average construction and completion segment margin per well

  $ 24   $ 25   $ 28   $ 29   $ 29   $ 29   $ 39
                                         

Segment margin

  $ 6,897   $ 11,332   $ 17,522   $ 3,985   $ 5,497   $ 13,537   $ 17,652
                                         

Net wells drilled

    282     450     615     136     187     479     459
                                         

Nine months ended September 30, 2006 compared to nine months ended September 30, 2005

Gas and Oil Production

Our natural gas revenues were $59.3 million in the nine months ended September 30, 2006, an increase of $16.6 million (39%) from $42.7 million in the nine months ended September 30, 2005. The increase was attributable to an increase in the average sales price of natural gas of 22% and an increase of 14% in the volume of natural gas produced in the nine months ended September 30, 2006. The $16.6 million increase in natural gas revenues consisted of $9.3 million attributable to increases in natural gas sales prices and $7.3 million attributable to increased production volumes.

The increase in our gas production volumes resulted from production associated with new wells drilled for our investment partnerships. We believe that gas volumes will be favorably impacted in the remainder of 2006 as ongoing projects to extend and enhance the gathering systems of Atlas Pipeline in the Appalachian Basin are completed and wells drilled are connected in these areas of expansion.

Our oil revenues were $7.3 million in the nine months ended September 30, 2006, an increase of $1.2 million (20%) from $6.1 million in the nine months ended September 30, 2005, due to an increase in the average sales price of oil of 24% for the nine months ended September 30, 2006 as compared to the prior year similar period. The $1.2 million increase consisted of $1.4 million attributable to increases in sales prices partially offset by $217,000 attributable to decreased production volumes.

 


 

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Our production costs were $10.5 million in the nine months ended September 30, 2006, an increase of $4.1 million (64%) from $6.4 million in the nine months ended September 30, 2005. This increase includes an increase in transportation charges and labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period. The transportation fees charged to our wells connected to Atlas Pipeline’s gathering system were generally increased from $0.29 to $0.35 per mcf to 10% of the gas sales price during the nine months ended September 30, 2006.

Well Construction and Completion

Our well construction and completion segment margin was $17.7 million in the nine months ended September 30, 2006, an increase of $4.2 million (30%) from $13.5 million in the nine months ended September 30, 2005. During the nine months ended September 30, 2006, the increase of $4.2 million was attributable to an increase in the gross profit per well ($4.9 million) partially offset by a decrease in the number of wells drilled ($767,000). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well in the nine months ended September 30, 2006 resulted from an increase in the cost of tangible equipment, leases, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations.

It should be noted that “Liabilities associated with drilling contracts on our balance sheet includes $71.6 million of funds raised in our investment programs that have not been applied to the completion of wells as of September 30, 2006 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue. We expect to recognize this amount as revenue by March 31, 2007. During the twelve months ended September 30, 2006, we raised $199.8 million. We anticipate raising an additional $71.0 million in the fourth quarter of 2006, for a total of $218.6 million raised in calendar 2006. We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the twelve months ending December 31, 2007.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. Our administration and oversight fees were $8.5 million in the nine months ended September 30, 2006, an increase of $1.1 million (14%) from $7.4 million in the nine months ended September 30, 2005. This increase resulted from an increase in the number of wells managed for our investment partnerships in the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005.

Well Services

Our well services revenues were $9.5 million in the nine months ended September 30, 2006, an increase of $2.2 million (30%) from $7.3 million in the nine months ended September 30, 2005. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended September 30, 2006.

Our well services expenses were $5.5 million in nine months ended September 30, 2006, an increase of $1.5 million (39%) from $4.0 million in the nine months ended September 30, 2005. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

 


 

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Gathering

We charge transportation fees to our investment partnership wells that are connected to Atlas Pipeline’s gathering systems. We in turn pay these fees, plus an additional amount to bring the total transportation charge up to, generally, 16% of the gas sales price, to Atlas Pipeline in accordance with our gathering agreements with it.

Our gathering fee to Atlas Pipeline was $22.7 million for the nine months ended September 30, 2006, an increase of $6.1 million (36%) from $16.6 in the nine months ended September 30, 2005. The increase in the nine months ended September 30, 2006 is primarily a result of higher natural gas prices and increased volumes of gas transported due to an increase in the number of wells we drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems; the expenses associated with these are shown as gathering fees on our combined statements of income.

Upon the completion of this offering, Atlas America will assume our obligation to pay gathering fees to Atlas Pipeline. We will be obligated to pay the gathering fees we receive from our investment partnerships to Atlas America, with the result that our gathering revenues and expenses within our partnership management segment will net to $0. We will also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense.

General and Administrative

Our general and administrative expenses were $15.4 million in the nine months ended September 30, 2006, an increase of $5.2 million (52%) from $10.2 million in the nine months ended September 30, 2005. These expenses include, among other things, salaries and benefits not allocated to a specific activity, costs of running our corporate office, partnership syndication activities and outside services.

The increase in the nine months ended September 30, 2006 is principally attributed to the following:

 

Ø   Net syndication costs increased $1.9 million due to an increase in expenses related to our increased fund raising in our public and private investment partnerships.

 

Ø   Professional and legal fees increased $1.2 million primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance.

 

Ø   Salaries and wages, including non-cash stock compensation, increased $1.1 million due to the increase in executive salaries and in the number of employees as a result of our spin-off from Resource America.

 

Ø   Directors’ fees increased $889,000 as a result of Atlas America’s spin-off from Resource America.

 

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $1.0 million in the nine months ended September 30, 2006, an increase of $652,000 (168%) from $389,000 in the nine months ended September 30, 2005. This increase resulted from an increase in allocations from Resource America for executive management and administrative services, including rent allocations for our offices in Philadelphia, PA and New York City.

 


 

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Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 22% in the nine months ended September 30, 2006, compared to 19% in the nine months ended September 30, 2005. Depletion expense per Mcfe was $2.04 in the nine months ended September 30, 2006, an increase of $0.57 (39%) per Mcfe from $1.47 in the nine months ended September 30, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase to $14.8 million in the nine months ended September 30, 2006 compared to $9.5 million in the nine months ended September 30, 2005. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Three months ended December 31, 2005 compared to three months ended December 31, 2004

Our natural gas revenues were $21.9 million in the three months ended December 31, 2005, an increase of $9.2 million (72%) from $12.7 million in the three months ended December 31, 2004. The increase in the three months ended December 31, 2005 was attributable to an increase in the average sales price of natural gas of 63% for the three months ended December 31, 2005 and an increase of 6% in the volume of natural gas produced in the three months ended December 31, 2005. The $9.2 million increase in gas revenues in the three months ended December 31, 2005 as compared to the prior period consisted of $8.0 million attributable to increases in natural gas sales prices, and $1.2 attributable to increased production volumes.

Our oil revenues were $2.2 million in the three months ended December 31, 2005, an increase of $285,000 (15%), from $1.9 million in the three months ended December 31, 2004, primarily due to an increase in the average sales price of oil of 19% for the three months ended December 31, 2005. The $285,000 increase in oil revenues in three months ended December 31, 2005 as compared to the prior period consisted of $369,000 attributable to increases in sales prices, partially offset by a decrease of $84,000 attributable to decreased production volumes.

Our production costs were $2.4 million in the three months ended December 31, 2005, an increase of $691,000 (40%) from $1.7 million in the three months ended December 31, 2004. These increases include an increase in pumping labor and an increase in transportation expenses associated with increased production volumes and natural gas sales prices, as a portion of our wells are charged transportation based on the sales price of the gas transported. The decrease in production costs as a percent of production revenues in the three months ended December 31, 2005 as compared to December 31, 2004 was an increase in our average sales price which more than offset the slight-increase in production costs per mcfe.

Well Construction and Completion

Our well construction and completion segment margin was $5.5 million in the three months ended December 31, 2005, an increase of $1.5 million (38%) from $4.0 million in the three months ended December 31, 2004. During the three months ended December 31, 2005, the increase of $1.5 million was attributable to an increase in the number of wells drilled ($1.5 million) plus an increase in the gross profit per well ($13,000). Since our drilling contracts are on a “cost plus” basis (typically cost plus 15%), an increase in our average cost per well also results in an increase in our average revenue per well. The increase in our average cost per well in the three months ended December 31, 2005 resulted from an increase in the cost of tangible equipment, leases, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations.

 


 

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It should be noted that “Liabilities associated with drilling contracts on our balance sheet includes $59.0 million of funds raised in our investment programs that have not been applied to the completion of wells as of December 31, 2005 due to the timing of drilling operations, and thus have not been recognized as well construction and completion revenue.

Administration and Oversight

Administration and oversight represents supervision and administrative fees earned for the drilling and subsequent management of wells for our investment partnerships. Our administration and oversight fees were $3.0 million in the three months ended December 31, 2005, an increase of $808,000 (37%) from $2.2 million in the three months ended December 31, 2004. This increase resulted from an increase in the number of wells managed for our investment partnerships in the three months ended December 31, 2005 as compared to the three months ended December 31, 2004.

Well Services

Our well services revenues were $2.6 million in the three months ended December 31, 2005, an increase of $313,000 (14%) from $2.3 million in the three months ended December 31, 2004. This increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in the twelve months ended December 31, 2005.

Our well services expenses were $1.5 million in three months ended December 31, 2005, an increase of $296,000 (25%) from $1.2 million in the three months ended December 31, 2004. This increase was attributable to an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in the number of wells we operate for our investment partnerships.

Gathering

Our gathering fee to Atlas Pipeline was $7.9 million for the three months ended December 31, 2005, an increase of $2.6 million (50%) from $5.3 million in the three months ended December 31, 2004. The increase in the three months ended December 31, 2005 was primarily a result of higher natural gas prices and increased volumes of gas transported due to an increase in the number of wells we drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems; the expenses associated with these are shown as gathering fees on our combined statements of income.

General and Administrative

Our general and administrative expenses were $5.8 million in the three months ended December 31, 2005, an increase of $3.7 million (170%) from $2.1 million in the three months ended December 31, 2004. These expenses include, among other things, salaries and benefits not allocated to a specific activity, costs of running our corporate office, partnership syndication activities and outside services.

The increase in the three months ended December 31, 2005 is principally attributed to the following:

 

Ø   Net syndication costs increased $1.1 million due to an increase in expenses related to our increased fund raising in our public and private investment partnerships.

 

Ø   Professional and legal fees increased $680,000 primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance.

 

Ø   Salaries and wages, including non-cash stock compensation, increased $1.2 million due to the increase in executive salaries and in the number of employees as a result of our spin-off from Resource America.

 

Ø   Directors’ fees increased $250,000 as a result of Atlas America’s spin-off from Resource America.

 


 

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Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $163,000 in the three months ended December 31, 2005, a decrease of $50,000 (23%) from $213,000 in the three months ended December 31, 2004. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services, as we now directly employ many of the individuals previously being allocated to us and therefore include their compensation in our general and administrative expenses.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 18% in the three months ended December 31, 2005 and December 31, 2004. Depletion expense per mcfe was $2.01 in the three months ended December 31, 2005, an increase of $.73 (57%) per mcfe from $1.28 in the three months ended December 31, 2004. Increases in our depletable basis and production volumes caused depletion expense to increase $1.7 million (65%) to $4.4 million in the three months ended December 31, 2005 compared to $2.7 million in the three months ended December 31, 2004. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, production levels, product prices and changes in the depletable cost basis of our oil and gas properties.

Year ended September 30, 2005 compared to year ended September 30, 2004

Gas and Oil Production

Our natural gas revenues were $55.4 million in fiscal 2005, an increase of $12.9 million (30%) from $42.5 million in fiscal 2004. The increase was due to a 24% increase in the average sales price of natural gas and a 5% increase in production volumes. The $12.9 million increase in natural gas revenues consisted of $10.4 million attributable to price increases and $2.5 million attributable to volume increases.

Our oil revenues were $8.0 million in fiscal 2005, an increase of $2.1 million (35%) from $5.9 million in fiscal 2004. The increase resulted from a 55% increase in the average sales price of oil, partially offset by a 13% decrease in production volumes. The $2.1 million increase in oil revenues consisted of $3.3 million attributable to price increases, partially offset by $1.2 million attributable to volume decreases, as we drill primarily for natural gas rather than oil.

Our production costs were $8.2 million in fiscal 2005, an increase of $900,000 (12%) from $7.3 million in fiscal 2004. This increase includes normal operating expenses and coincides with the increased production volumes we realized from the increased number of wells we operate. In addition, there were increases in transportation expense as a result of increased natural gas prices as a portion of our wells are charged transportation based on the sales price of the gas transported. Rates charged to us for transportation vary based upon agreements put in place at the time the wells are drilled; some of these agreements have escalation clauses. Production costs as a percent of sales decreased from 15% in fiscal 2004 to 13% in fiscal 2005 as a result of an increase in our average sales price which more than offset the increase in production costs per Mcfe.

Our exploration costs were $900,000 in the year ended September 30, 2005, a decrease of $600,000 (42%) from $1.5 million in fiscal 2004. The decrease was primarily due to the dry hole costs of $704,000 incurred in 2004 upon determination that a well drilled in an exploratory area of our operations was not capable of economic production. No dry hole costs were incurred in 2005.

Well Construction and Completion

Our well construction and completion segment margin was $17.5 million in the year ended September 30, 2005, an increase of $6.2 million (55%) from $11.3 million in the year ended

 


 

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September 30, 2004. During the year ended September 30, 2005, the increase in segment margin was attributable to an increase in the number of wells drilled ($4.7 million) and an increase in the gross profit per well ($1.5 million). The increase in our average cost per well resulted from an increase in the cost of tangible equipment, leases, site preparation and reclamation expenses, as well as increased costs due to drilling into deeper formations.

It should be noted that “Liabilities associated with drilling contracts on our balance sheet as of September 30, 2005 included $49.9 million of funds raised in our investment partnerships in fiscal 2005 that had not been applied to drill wells as of September 30, 2005 due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenues.

Administration and Oversight

Our administration and oversight fees were $9.6 million in fiscal 2005, an increase of $1.2 million (14%) from $8.4 million in fiscal 2004. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in fiscal 2005 as compared to the prior year.

Well Services

Our well services revenues were $9.6 million in fiscal 2005, an increase of $1.2 million (13%) from $8.4 million in fiscal 2004. The increase resulted from an increase in the number of wells operated for our investment partnerships due to additional wells drilled in fiscal 2005.

Our well services expenses were $5.2 million in fiscal 2005, an increase of $769,000 (17%) from $4.4 million in fiscal 2004. The increase resulted from an increase in wages, benefits, and field office expenses associated with an increase in employees due to the increase in number of wells operated for our investment partnerships in fiscal 2005 as compared to fiscal 2004.

Gathering

Our gathering fee to Atlas Pipeline was $21.9 million in fiscal 2005, an increase of $4.7 million (27%) from $17.2 million in fiscal 2004. The increase was primarily a result of higher natural gas prices and increased volumes of gas transported due to our increase in the number of wells drilled. We also pay our proportional share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense. We also own several small gathering systems; the expenses associated with these are shown as gathering fees on our combined statements of income.

General and Administrative

Our general and administrative expenses were $12.3 million in fiscal 2005, an increase of $2.1 million (21%) from $10.2 million in fiscal 2004. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our energy corporate office, partnership syndication activities and outside services. The increase in the year ended September 30, 2005 as compared to the prior year period is attributable principally to the following:

 

Ø   Professional fees and insurance increased $1.5 million, which includes the implementation of Sarbanes-Oxley Section 404.

 

Ø   Office operations, including rent and travel expenses increased $503,000 due to an increase in the number of employees as a result of our continued growth.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $602,000 in fiscal 2005, a decrease of $448,000 (43%) from $1,050,000 in fiscal 2004. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services as we now directly employ many of the individuals previously being allocated to us and therefore include their compensation in our general and administrative expenses.

 


 

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Depletion

Depletion of oil and gas properties as a percentage of oil and gas revenues was 19% in fiscal 2005 compared to 21% in fiscal 2004. Depletion was $1.42 per Mcfe in fiscal 2005, an increase of $.20 per Mcfe (16%) from $1.22 per Mcfe in fiscal 2004. Increases in our depletable basis and production volumes caused depletion expense to increase $2.0 million to $12.2 million in fiscal 2005 compared to $10.2 million in fiscal 2004. The variances from period to period are directly attributable to changes in our oil and gas reserve quantities, product prices and changes in the depletable cost basis of our oil and gas properties.

Year ended September 30, 2004 compared to year ended September 30, 2003

Gas and Oil Production

Our natural gas revenues were $42.5 million in fiscal 2004, an increase of $8.3 million (24%) from $34.2 million in fiscal 2003. The increase was due to a 19% increase in the average sales price of natural gas and a 4% increase in production volumes. The $8.3 million increase in natural gas revenues consisted of $6.4 million attributable to price increases and $1.9 million attributable to volume increases.

Our oil revenues were $5.9 million in fiscal 2004, an increase of $1.6 million (38%) from $4.3 million in fiscal 2003. The increase resulted from a 22% increase in the average sales price of oil and a 13% increase in production volumes. The $1.6 million increase in oil revenues consisted of $951,000 attributable to price increases and $689,000 attributable to volume increases.

Our production costs were $7.3 million in fiscal 2004, an increase of $519,000 (8%) from $6.8 million in fiscal 2003. This increase includes normal operating expenses and coincides with the increased production volumes we realized from the increased number of wells we operate. Production costs as a percent of sales decreased from 18% in fiscal 2003 to 15% in fiscal 2004 as a result of an increase in our average sales price which more than offset the slight increase in production costs per Mcfe.

Our exploration costs were $1.5 million in the year ended September 30, 2004, a decrease of $166,000 (10%) from fiscal 2003. We attribute the decrease in fiscal 2004 as compared to the prior period is principally due to the following:

 

Ø   The benefit we received for our contribution of well sites to our investment partnerships increased $813,000 in fiscal 2004 as compared to fiscal 2003 as a result of more wells drilled; which was offset in part by:

 

Ø   $704,000 in dry hole costs we incurred upon making the determination that a well drilled in an exploratory area of our operations was not capable of economic production.

Well Construction and Completion

Our well construction and completion segment margin was $11.3 million in the year ended September 30, 2004, an increase of $4.4 million (64%) from $6.9 million in the year ended September 30, 2003. During the year ended September 30, 2004, the increase in segment margin was attributable to an increase in the number of wells drilled ($4.2 million) and an increase in the gross profit per well ($204,000). The increase in our average cost per well resulted from an increase in the cost of tangible equipment, leases and reclamation expenses.

It should be noted that “Liabilities associated with drilling contracts on our balance sheet includes $26.5 million of funds raised in our investment partnerships in the fourth quarter of fiscal 2004 that had

 


 

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not been applied to drill wells as of September 30, 2004 due to the timing of drilling operations, and thus had not been recognized as well construction and completion revenues. We recognized this amount as income in fiscal 2005.

Administration and Oversight

Our administration and oversight fees were $8.4 million in fiscal 2004, an increase of $3.3 million (65%) from $5.1 million in fiscal 2003. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in fiscal 2004 as compared to the prior year.

Well Services

Our well services revenues were $8.4 million in fiscal 2004, an increase of $795,000 (10%) from $7.6 million in fiscal 2003. The increase resulted from an increase in the number of wells operated due to additional wells drilled in fiscal 2004.

Our well services expenses were $4.4 million in fiscal 2004, an increase of $625,000 (17%) from $3.8 million in fiscal 2003. The increase resulted from an increase in costs associated with a greater number of wells operated in fiscal 2004 as compared to fiscal 2003.

Gathering

Our gathering fee to Atlas Pipeline was $17.2 million in fiscal 2004, an increase of $2.6 million (18%) from $14.6 million in fiscal 2005. This increase was primarily a result of higher natural gas sales prices as these fees are generally based on 16% of gas sales ultimately payable to Atlas Pipeline in accordance with its gathering agreements with Atlas America.

General and Administrative

Our general and administrative expenses were $10.2 million in fiscal 2004, an increase of $1.8 million (21%) from $8.4 million in fiscal 2003. These expenses include, among other things, salaries and benefits not allocated to a specific energy activity, costs of running our corporate office, partnership syndication activities and outside services. The increase in the year ended September 30, 2004 as compared to the prior year is attributable principally to the following:

 

Ø   Net syndication costs increased $930,000 as we continue to increase our syndication activities and the drilling funds we raise in our public and private partnerships.

 

Ø   Legal and professional fees increased $787,000, which includes the implementation of Sarbanes-Oxley Section 404.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $1.1 million in fiscal 2004, a decrease of $350,000 (25%) from $1.4 million in fiscal 2003. This decrease resulted from a decrease in allocations from Resource America for executive management and administrative services as a result of an increase in our own executive staff in anticipation of our spin-off from Resource America.

Depletion

Depletion of oil and gas properties as a percentage of oil and gas revenues was 21% in both fiscal 2004 and fiscal 2003. Depletion was $1.22 per Mcfe in fiscal 2004, an increase of $0.21 per Mcfe (21%) from $1.01 per Mcfe in fiscal 2003. Higher volumes produced on our new wells in their first year of

 


 

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production caused depletion per Mcfe to increase in fiscal 2004 as compared to fiscal 2003. The

variances from period to period are directly attributable to changes in our oil and gas reserve quantities, product prices and changes in the depletable cost basis of our oil and gas properties.

LIQUIDITY AND CAPITAL RESOURCES

General

We fund our development and production operations with a combination of cash generated by operations, capital raised through investment partnerships, and if required, advances from Atlas America. The following table sets forth our sources and uses of cash (in thousands):

 

     Years ended September 30,    

Three months ended
December 31,

   

Nine months ended

September 30,

 
      2003     2004     2005     2004     2005     2005     2006  

Provided by operations

   $ 20,365     $ 42,523     $ 65,444     $ 22,399     $ 31,783     $ 43,045     $ 15,186  

Used in investing activities

     (22,112 )     (32,709 )     (59,050 )     (11,591 )     (17,185 )     (47,459 )     (53,926 )

Provided by (used in) financing activities

     34       (14,916 )     (320 )     (35 )     74       (285 )     74,428  
                                                        

Increase (decrease) in cash and cash equivalents

   $ (1,713 )   $ (5,102 )   $ 6,074     $ 10,773     $ 14,672     $ (4,699 )   $ 35,688  
                                                        

We had $56.6 million in cash and cash equivalents at September 30, 2006, as compared to $20.9 million at December 31, 2005. We had negative working capital of $39.0 million at September 30, 2006, an increase in working capital of $39.5 million from negative working capital of $78.5 million at December 31, 2005.

Capital requirements

During the nine months ended September 30, 2006, our capital expenditures related primarily to investments in our investment partnerships, in which we invested $52.5 million. For the nine months ended September 30, 2006 and the remainder of 2006, we funded and expect to continue to fund these capital expenditures through cash on hand, from operations and, until the closing of this offering, from advances from Atlas America. In fiscal 2005 and 2004 our capital expenditures related to investments in our investment partnerships totaled $57.9 million and $32.2 million, respectively.

The level of capital expenditures we must devote to our development and production operations depends upon the level of funds raised through our investment partnerships. Through the twelve months ended September 30, 2006 we had raised $199.8 million. We believe cash flows from operations and amounts available under our proposed credit facility will be adequate to fund our contributions to these partnerships. However, the amount of funds we raise and the level of our capital expenditures will vary in the future depending on market conditions for natural gas and other factors. During the nine months ended September 30, 2006, fiscal 2005 and 2004 we raised $147.6 million, $148.7 million and $107.7 million, respectively.

We expect to fund our maintenance capital expenditures with cash flow from operations and the temporary use of funds raised in our investment partnerships in the period before we invest these funds, while funding our investment capital expenditures and any expansion capital expenditures that we might incur with borrowings under our new credit facility as well as with the temporary use of funds raised in

 


 

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our investment partnerships in the period before we invest the funds. We estimate investment capital expenditures of $43.4 million during the twelve month period ending December 31, 2007, and no expansion capital expenditures, although that may change if opportunities are available to us in that period. We also estimate that we will have sufficient cash flow from operations after funding our maintenance capital expenditures to enable us to make our quarterly cash distributions in the amount of the IQD to unitholders through December 31, 2007. See “Cash distribution policy and restrictions on cash distributions.”

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

Proposed credit facility

Simultaneously with the closing of this offering, we intend to enter into a $250 million senior secured credit facility with Wachovia Bank, National Association, as administrative agent, Wachovia Capital Markets LLC, as lead arranger, and other lenders. The credit facility will allow us to borrow up to the determined amount of the borrowing base, which will be based upon the loan collateral value assigned to our various natural gas and oil properties. The initial borrowing base will be $155 million. The borrowing base will be subject to redetermination on March 14, 2007 and on a semi-annual basis thereafter. The credit facility will mature on the fifth anniversary of the closing date.

Our obligations under the new credit facility will be secured by mortgages on our natural gas and oil properties as well as a pledge of all of our ownership interests in our operating subsidiaries. We will be required to maintain the mortgages on properties representing at least 80% of our natural gas and oil properties. Additionally, the obligations under the new credit facility will be guaranteed by all of our existing operating subsidiaries and by any future subsidiaries.

Borrowings under the new credit facility will be available for development, exploitation and acquisition of natural gas and oil properties, working capital and general corporate purposes.

At our election, interest will be determined by reference to:

 

Ø   the London interbank offered rate, or LIBOR, plus an applicable margin between 1.00% and 1.75% per annum, depending on our usage of the facility; or

 

Ø   the higher of (i) the federal funds rate plus 0.50% or (ii) the Wachovia prime rate, plus, in each case, an applicable margin between 0.00% and 0.75% per annum, depending on our usage of the facility.

Interest will generally be payable quarterly for domestic bank rate loans and at the end of each applicable interest period for LIBOR loans.

The new credit facility will contain covenants that, among other things, limit our ability to:

 

Ø   incur indebtedness;

 

Ø   grant certain liens;

 

Ø   enter into certain leases;

 

Ø   make certain loans, acquisitions, capital expenditures and investments;

 

Ø   enter into hedging arrangements that exceed 85% of our proved reserves;

 

Ø   make any change to the character of our business or the business of the investment partnerships;

 

Ø   merge or consolidate; or

 

Ø   engage in certain asset dispositions, including a sale of all or substantially all of our assets.

 


 

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The new credit facility will require us to maintain a current ratio (defined as the ratio of current assets to current liabilities) of not less than 1.0 to 1.0; a funded debt to EBITDA ratio of not more than 3.5 to 1.0; and a minimum interest coverage ratio (defined as our EBITDA divided by our interest expense) of not less than 2.5 to 1.0. The credit facility defines EBITDA for any period of four fiscal quarters as the sum of consolidated net income for the period plus interest, income taxes, depreciation, depletion and amortization.

Upon completion of this offering, we will have the ability to pay distributions to unitholders as long as there has not been an event of default and an event of default would not result from the distribution.

If an event of default exists under the credit facility, the lenders will be able to accelerate the maturity of the credit facility and exercise other customary rights and remedies. Each of the following is an event of default:

 

Ø   failure to pay any principal when due or any interest, fees or other amounts in the credit facility;

 

Ø   failure to pay any principal or interest on any of our other debt aggregating $2.5 million or more;

 

Ø   a representation, warranty or certification made under the loan documents or in any certificate furnished thereunder is false or misleading as of the time made or furnished in any material respect;

 

Ø   failure to perform under any obligation set forth in the credit facility, subject to a grace period;

 

Ø   an event having a material adverse effect on us, any of the guarantors or the collateral used to secure indebtedness;

 

Ø   admission in writing the inability to, or being generally unable to, pay debts as they become due;

 

Ø   bankruptcy or insolvency events;

 

Ø   commencement of a proceeding or case in any court of competent jurisdiction, without application or consent, involving:

 

  Ø   liquidation, reorganization, dissolution or winding-up; or

 

  Ø   the appointment of a trustee, receiver, custodian, liquidator or the like;

 

Ø   the entry of, and failure to pay, one or more judgments in excess of $2.5 million;

 

Ø   the loan documents cease to be in full force and effect or cease to create a valid, binding and enforceable lien;

 

Ø   a change of control, generally defined as (i) a group or person acquiring 35% or more of our outstanding voting units (other than Atlas America and its affiliates), (ii) our failure to own 85% or more of the outstanding shares of voting capital stock of any of our subsidiaries that is a guarantor under the credit facility, (iii) our failure to own 100% of Atlas Energy Operating Company or (iv) the failure of Atlas America or any of its wholly-owned subsidiaries to own at least 51% of the equity of our manager; and

 

Ø   concealment of property with the intent to hinder, delay or defraud any lender with respect to their rights to such property.

CASH FLOWS

Nine months ended September 30, 2006 compared to September 30, 2005

Operating activities.    Cash provided by operations is an important source of short-term liquidity for us. It is directly affected by changes in the price of natural gas and oil, interest rates and our ability to

 


 

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raise funds from our investment partnerships. Net cash provided by operating activities decreased $27.8 million in the nine months ended September 30, 2006 to $15.2 million from $43.0 million in the nine months ended September 30, 2005, substantially as a result of the following:

 

Ø   Net income before depreciation and amortization increased $10.9 million in the nine months ended September 30, 2006 as compared to the prior year period, principally as a result of higher natural gas and oil prices and increased drilling profits.

 

Ø   Changes in operating assets and liabilities decreased operating cash flow by $5.2 million in the nine months ended September 30, 2006, compared to the nine months ended September 30, 2005, principally as a result of a decrease in the change in accounts payable and liabilities associated drilling contracts of $4.9 million related to the increase in our drilling activities as well as a decrease in the change in accounts receivable and prepaid expenses of $1.1 million related to increased gas and oil production revenues.

 

Ø   An increase in repayments to affiliates decreased operating cash flows by $34.1 million in the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005, principally due to an increase in cash generated by our operations.

Investing activities.    Cash used in our investing activities increased $6.4 million in the nine months ended September 30, 2006 to $53.9 million from $47.5 million in the nine months ended September 30, 2005 primarily as a result of an increase in capital expenditures of $6.6 million due to an increase in the number of wells we drilled.

Financing activities.    Cash provided by our financing activities increased $74.7 in the nine months ended September 30, 2006 to $74.4 from cash used of $285,000 in the nine months ended September 30, 2005 as a result of proceeds of $74.5 million from Atlas Pipeline Holdings’ initial public offering. There was no such offering in the nine months ended September 30, 2005.

Three months ended December 31, 2005 compared to three months ended December 31, 2004

Operating activities.    Net cash provided by operating activities increased $9.4 million in the three months ended December 31, 2005 to $31.8 million from $22.4 million in the three months ended December 2004, substantially as a result of the following:

 

Ø   an increase in net income before depreciation, depletion and amortization of $5.1 million as compared to the prior year similar period, principally as a result of higher natural gas prices and drilling profits.

 

Ø   a decrease in repayments to affiliates increased operating cash flows by $4.3 million.

Investing activities.    Cash used in our investing activities increased $5.6 million in the three months ended December 31, 2005 to $17.2 million from $11.6 million in the three months ended December 31, 2004 primarily as a result of an increase in capital expenditure of $5.5 million due to an increase in the number of wells drilled.

Financing activities.    Cash provided by our financing activities increased $109,000 in the three months ended December 31, 2005 to $74,000 from cash used of $35,000 in the three months ended December 2004, primarily due to borrowings of $91,000 in the three months ended December 31, 2005.

 


 

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Year ended September 30, 2005 compared to year ended September 30, 2004

Operating activities.    Net cash provided by operating activities increased $22.9 million in fiscal 2005 to $65.4 million from $42.5 million in fiscal 2004, substantially as a result of the following:

 

Ø   An increase in net income before depreciation, depletion and amortization of $15.9 million in fiscal 2005 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits.

 

Ø   Changes in operating assets and liabilities increased operating cash flows by $19.9 million in fiscal 2005, compared to fiscal 2004, primarily due to an increase in liabilities associated with our drilling contracts of $23.7 million related to an increase in advance payments received. This increase was partially offset by an increase of $5.3 million in accounts receivable related to increased gas and oil production revenues. Our level of liabilities is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships.

 

Ø   An increase in repayments to affiliates decreased operating cash flows by $13.6 million, principally as a result of an increase in cash generated by our operations.

Investing activities.    Net cash used in our investing activities increased $26.3 million in fiscal 2005 to $59.0 million from $32.7 million in fiscal 2004 primarily from a $25.9 million increase in capital expenditures related to the increase in the number of wells drilled.

Financing activities.    Net cash used in our financing activities decreased $14.6 million in fiscal 2005 to $320,000 from $14.9 million in fiscal 2004, as a result of proceeds we received of $37.0 million in fiscal 2004 from Atlas America’s initial public offering of common stock; there were no such offerings in fiscal 2005.

Year ended September 30, 2004 compared to year ended September 30, 2003

Operating activities.    Net cash provided by operating activities increased $22.1 million in fiscal 2004 to $42.5 million from $20.4 million in fiscal 2003, substantially as a result of the following:

 

Ø   Changes in operating assets and liabilities decreased operating cash flow by $2.6 million in fiscal 2004 compared to fiscal 2003, primarily due to a decrease of $9.3 million in liabilities associated with our drilling contracts, offset by increases of $3.1 million and $3.3 million in prepaid expenses and other operating assets and liabilities. Our level of liabilities is dependent upon the remaining amount of our drilling obligations at any balance sheet date, which is dependent upon the timing of funds raised through our investment partnerships.

 

Ø   An increase in net income before depreciation, depletion and amortization of $13.8 million in fiscal 2004 as compared to the prior fiscal year principally a result of higher natural gas prices and drilling profits.

 

Ø   A decrease in repayments to affiliates increased operating cash flows by $10.9 million.

Investing activities.    Net cash used in our investing activities increased $10.6 million in fiscal 2004 to $32.7 million from $22.1 million in fiscal 2003 primarily as a result of increases in our capital expenditures related to the increase in the number of wells we drilled.

Financing activities.    Net cash used in our financing activities increased $1.5 million in fiscal 2004 to $7.2 million from $5.7 million in fiscal 2003, as a result of the following:

 

Ø   We received proceeds of $37.0 million from Atlas America’s initial public offering in fiscal 2004.

 


 

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Ø   Payments to Resource America in the form of repayments of advances and dividends increased by $38.7 million, principally as a result of a one-time special dividend paid by Atlas America to Resource America in fiscal 2004 as part of the transactions leading to Atlas America’s spin-off from Resource America.

CHANGES IN PRICES AND INFLATION

Our revenues, the value of our assets, our ability to obtain bank loans or additional capital on attractive terms and our ability to finance our drilling activities through investment partnerships have been and will continue to be affected by changes in oil and gas prices. Natural gas and oil prices are subject to significant fluctuations that are beyond our ability to control or predict. During the nine months ended September 30, 2006 and 2005, we received an average of $9.03 and $7.41 per Mcf of natural gas and $64.59 and $52.23 per Bbl of oil, respectively. During the three months ended December 31, 2005 and 2004, we received an average of $11.06 and $6.80 per Mcf of natural gas and $56.13 and $47.17 per Bbl of oil, respectively. During fiscal 2005, we received an average of $7.26 per Mcf of natural gas and $50.91 per Bbl of oil as compared to $5.84 per Mcf and $32.85 per Bbl in fiscal 2004 and $4.92 per Mcf and $26.91 per Bbl of oil in fiscal 2003.

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

ENVIRONMENTAL REGULATION

To date, compliance with environmental laws and regulations has not had a material impact on our capital expenditures, earnings or competitive position. For instance, we are evaluating the impact of spill prevention plan requirements on our operations, including pending changes by United Stated Environmental Protection Agency to the federal regulations that require compliance by October 31, 2007. We cannot assure you that compliance with environmental laws and regulations will not, in the future, materially adversely affect our operations through increased costs of doing business or restrictions on the manner in which we conduct our operations.

DIVIDENDS

There were no dividends paid in the twelve months ended September 30, 2006 or the year ended September 30, 2005. In the year ended September 30, 2004, Atlas America paid a dividend of $52.1 million to Resource America.

Following the closing of this offering, we intend to make cash distributions to our common units and Class A units at an initial distribution rate of $0.42 per unit per quarter ($1.68 per unit on an annualized basis). As required by our limited liability company agreement, we expect to distribute all of our available cash. As a result, we expect that we will rely upon external financing sources, including commercial borrowings and other debt and common unit issuances, to fund our acquisition and expansion capital expenditures, as well as our working capital needs.

 


 

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CONTRACTUAL OBLIGATIONS AND COMMERCIAL COMMITMENTS

The following table summarizes our contractual obligations at September 30, 2006:

 

         

Payments due by period

(in thousands)

Contractual cash obligations:    Total   

Less than

1 year

   2 – 3
Years
  

4 – 5

Years

  

After 5

years

Total debt

   $ 90    $ 52    $ 38    $ —      $ —  

Secured revolving credit facilities

     —        —        —        —        —  

Operating lease obligations

     1,837      585      925      326      1

Capital lease obligations

     —        —        —        —        —  

Unconditional purchase obligations

     —        —        —        —        —  

Other long-term obligations

     —        —        —        —        —  
                                  

Total contractual cash obligations

   $ 1,927    $ 637    $ 963    $ 326    $ 1
                                  

 

         

Payments due by period

(in thousands)

Other commercial commitments:    Total    Less than
1 year
   1 – 3
Years
   4 – 5
Years
   After 5
years

Standby letters of credit

   $ 1,475    $ 1,475    $ —      $ —      $ —  

Guarantees

     —        —        —        —        —  

Standby replacement commitments

     —        —        —        —        —  

Other commercial commitments

     —        —        —        —        —  
                                  

Total commercial commitments

   $ 1,475    $ 1,475    $ —      $ —      $ —  
                                  

CRITICAL ACCOUNTING POLICIES

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

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

Accounts receivable and allowance for possible losses

Through our business segments, we engage in credit extension, monitoring, and collection. In evaluating our allowance for possible losses, we perform ongoing credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s current creditworthiness, as determined by our review of our customer’s credit information. We extend credit on an unsecured basis to many of our energy customers. At December 31, 2005, September 30, 2006 and September 30, 2005, our credit evaluation indicated that we have no need for an allowance for possible losses for our oil and gas receivables.

 


 

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Reserve estimates

Our estimates of our 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 our reserves. As a result, our estimates of our 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 our estimates or estimates contained in the reserve reports and may affect our ability to pay amounts due under our credit facilities or cause a reduction in our energy credit facilities. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Impairment of oil and gas properties

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

Dismantlement, restoration, reclamation and abandonment costs

As described in Note 4 to the combined financial statements, we follow SFAS No. 143, “Accounting for Asset Retirement Obligations.” Under SFAS No. 143, estimated asset retirement costs are recognized when the asset is placed in service, and are amortized using the units-of-production method. On an annual basis, we review our estimates of the costs of future dismantlement, restoration, reclamation and abandonment of our natural gas and oil-producing properties. We also review our estimates of the salvage value of equipment recoverable upon abandonment. As of December 31, 2005, September 30, 2006 and September 30, 2005, our estimate of salvage values was greater than or equal to our estimate of the costs of future dismantlement, restoration, reclamation and abandonment.

Inherent in the fair value calculation of asset retirement obligations are numerous assumptions and judgments including the estimated remaining lives of the wells, the estimated cost to plug and abandon the wells in the future, inflation factors, credit adjusted discount rates and changes in the legal regulatory requirements. To the extent future revisions to these assumptions impact the fair value of our existing asset retirement obligation, a corresponding adjustment is made to our oil and gas properties.

During fiscal 2005 we experienced significant increases in the cost of plugging and the salvage value of recoverable equipment associated with our wells. We are unable to predict whether these increases will continue to affect us in the future. A decrease in salvage values or an increase in dismantlement, restoration, reclamation and abandonment costs from those we have estimated, or changes in our estimates or costs, could reduce our gross profit from operations.

 


 

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Goodwill and other long-lived assets

Goodwill and other intangibles with an indefinite useful life are no longer amortized, but instead are assessed for impairment annually. We have recorded goodwill of $35.2 million in connection with several acquisitions of assets. In assessing impairment of goodwill, we use estimates and assumptions in estimating the fair value of reporting units. If under these estimates and assumptions we determine that the fair value of a reporting unit has been reduced, the reduction can result in an “impairment” of goodwill. However, future results could differ from the estimates and assumptions we use. Events or circumstances which might lead to an indication of impairment of goodwill would include, but might not be limited to, prolonged decreases in expectations of long-term well servicing and/or drilling activity or rates brought about by prolonged decreases in natural gas or oil prices, changes in government regulation of the natural gas and oil industry or other events which could affect the level of activity of exploration and production companies.

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

Revenue recognition

We conduct certain activities through, and a portion of our revenues are attributable to, our investment partnerships. These investment partnerships raise capital from investors to drill gas and oil wells. We serve as the managing general partner of the investment partnerships and assume customary rights and obligations for them. As a general partner, we are liable for partnership liabilities and can be liable to limited partners if we breach our responsibilities with respect to the operations of the partnerships. The income from our general partner interest is recorded when the gas and oil are sold by a partnership.

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

We recognize gathering revenues at the time the natural gas is delivered to the purchaser.

We recognize well services revenues at the time the services are performed.

We are entitled to receive administration and oversight fees according to the respective partnership agreements. We recognize such fees as income when earned.

We record the income from the working interests and overriding royalties of wells we own an interest in when the gas and oil are delivered.

RECENTLY ISSUED FINANCIAL ACCOUNTING STANDARDS

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements”, or

 


 

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SAB 108. SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. We are required to initially apply SAB 108 in connection with the preparation for our annual financial statements for the year ending December 31, 2006. We do not expect the application of SAB 108 to have a material effect on our financial position or results of operations.

In September 2006, the Financial Accounting Standards Board, or FASB, issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement,” or SFAS 157. SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for us beginning January 1, 2008. We are currently evaluating the impact of the adoption of SFAS 157 on our financial position or results of operations.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109”, or FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for the Company beginning January 1, 2007. We are currently evaluating the impact of the adoption of FIN 48 on our financial position and results of operations.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” or SFAS 154. SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on our financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” or FIN 47, which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement cost will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in Statement No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 was effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. Management is currently evaluating the impact of the adoption of FIN 47 on our financial position and results of operations.

In April 2005, the FASB issued FASB Staff Position (“FSP”) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas

 


 

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Producing Companies” and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP was required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The application of the FSP did not have a significant impact on our financial position or results of operations.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates and oil and gas prices. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than trading.

General

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

The following analysis presents the effect on our earnings, cash flows and financial position as if hypothetical changes in market risk factors occurred on September 30, 2006. Only the potential impacts of hypothetical assumptions are analyzed. The analysis does not consider other possible effects that could impact our business.

Commodity price risk

Our major market risk exposure in commodities is fluctuations in the pricing of our gas and oil production. Realized pricing is primarily driven by the prevailing worldwide prices for crude oil and spot market prices applicable to United States natural gas production. Pricing for gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use physical hedges. These transactions are similar to NYMEX-based futures contracts, swaps and options, but also require firm delivery of the hedged quantity. Thus, we limit these arrangements to much smaller quantities than those projected to be available at any delivery point.

 


 

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We also negotiate with certain purchasers for delivery of a portion of natural gas we will produce for the upcoming twelve months. The prices under most of our gas sales contracts are negotiated on an annual basis and are index-based. Our risk management objective is to lock in a range of pricing for expected production volumes. Considering those volumes for which we have entered into physical or financial hedge agreements for the twelve month period ending December 31, 2007, and current indices, a theoretical 10% upward or downward change in the price of natural gas would result in a change in net income of approximately $2.5 million.

We also enter into natural gas futures and 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.

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

For the twelve month period ending December 30, 2007, we have hedged, through both physical and financial hedges, approximately 77% of our projected natural gas volumes. At September 30, 2006, we had allocated to us 119 open natural gas futures contracts related to natural gas sales covering 38.1 million MMBtus of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.85 per MMBtu. We recognized a gain of $4.9 million on settled contracts covering natural gas production for the nine months ended September 30, 2006. We recognized no gains or losses during the nine months ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. We did not recognize any gains or losses on hedging in the nine months ended September 30, 2005.

At September 30, 2005 and 2004, we had no open natural gas futures contracts allocated to us related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. We recognized no losses on settled contracts for the years ended September 30, 2004 and 2005. We recognized no gains or losses during the three year period ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

 


 

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As of September 30, 2006, we had the following natural gas hedged volumes allocated to us:

 

Twelve month period

     ending September 30, 

   Volumes(1)
(MMBtu)
   Average
fixed price
(per MMBtu)
   Fair value
asset(2)
(in thousands)

2007

   10,110,000    $ 9.26    $ 20,116

2008

   14,640,000      8.75      9,945

2009

   10,950,000      8.65      7,862

2010

   2,430,000      8.61      1,650
              
   38,130,000       $ 39,573
              

(1)   Includes volumes hedged on behalf of our investment partnerships. Reflects financial hedges only.
(2)   Fair value based on forward NYMEX natural gas prices, as applicable, on September 30, 2006.

Of the $39.6 million net unrealized hedge gain, our retained portion is $17.4 million and $22.2 million has been reallocated to our investment partnerships.

Subsequent to September 30, 2006, we entered into the following natural gas hedges (includes volumes hedged on behalf of our investment partnerships):

 

Fixed price swaps

  

Volumes
(MMBtu)

 

  

Average
fixed price
(per MMBtu)

 

Twelve month period

     ending December 31,

     

2007

   1,800,000    $ 7.88

2008

   1,560,000      8.17

2009

   6,000,000      7.82

2010

   4,800,000      7.46

Costless collars

         

Twelve month period

     ending December 31,

   Volumes
(MMBtu)
   Average floor
and cap

2007

   1,800,000    $ 7.50 – 8.60

2008

   1,560,000      7.50 – 9.40

 


 

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Business

OVERVIEW

We are a limited liability company focused on the development and production of natural gas and, to a lesser extent, oil principally in the Appalachian Basin. We sponsor and manage tax-advantaged investment partnerships, in which we coinvest, to finance the exploitation and development of our acreage. Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our natural gas and oil production business as well as the fee-based revenues from our partnership management business.

We were formed in 2006 to own and operate substantially all of the natural gas and oil assets and the investment partnership management business of Atlas America, Inc. (Nasdaq: ATLS). Atlas America has been involved in the energy industry since 1968, expanding its operations in 1998 when it acquired The Atlas Group 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 is a separate entity from us, and its securities are not being offered in this offering.

We are managed by our manager, a wholly-owned subsidiary of Atlas America. Through our manager, the Atlas America personnel currently responsible for managing our assets and capital raising will continue to do so on our behalf upon completion of this offering.

As of September 30, 2006, our principal assets consisted of:

 

Ø   working interests in 6,415 gross producing gas and oil wells;

 

Ø   overriding royalty interests in 632 gross producing gas and oil wells;

 

Ø   our investment partnership business, which includes equity interests in 91 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

 

Ø   approximately 568,900 gross (516,200 net) acres, primarily in the Appalachian Basin, over half of which, or approximately 308,300 gross (294,800 net) acres, are undeveloped; and

 

Ø   an interest in a joint venture that gives us the right to drill up to 300 net wells before June 30, 2007 on approximately 212,000 acres in Tennessee.

In addition, at March 31, 2006, the date of our most recent reserve report, we had proved reserves of 170.9 Bcfe, including the reserves net to our equity interest in the investment partnerships and our direct interests in producing wells.

For the twelve month period ended September 30, 2006, we produced 25,924 Mcfe/d which includes the proportionate share of production from our investment partnerships as well as our direct interests in producing wells. This resulted in an average reserve life of approximately 18 years based on our proved reserves at March 31, 2006.

According to Rigdata.com, we were the 11th most active operator in the United States based on well starts from January 2006 to October 2006. As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

We fund the drilling of natural gas and oil wells on our acreage by sponsoring and managing tax-advantaged investment partnerships. We generally structure our investment partnerships so that, upon formation of a partnership, we coinvest in and contribute leasehold acreage to it, enter into drilling and well operating agreements with it and become its managing general partner.

 


 

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We derive substantially all of our revenues from our equity interest in the oil and gas produced by the investment partnerships as well as the fees paid by the partnerships to us for acting as the managing general partner as follows:

 

Ø   Gas and oil production.    We receive an interest in each investment partnership proportionate to the value of our coinvestment in it and the value of the acreage we contribute to it, typically 27% to 30% of the overall capitalization of a particular partnership. We also receive an incremental interest in each partnership, typically 7%, for which we do not make any additional capital contribution. Consequently, our equity interest in the reserves and production of each partnership is typically between 34% and 37%.

 

Ø   Partnership management.    As managing general partner of our investment partnerships, we receive the following fees:

 

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

 

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

 

  Ø   Well services.    Each partnership pays us a monthly per well operating fee, currently $100 to $457, for the life of the well. Because we coinvest in the partnerships, the net fee that we receive is reduced by our proportionate interest in the well.

 

  Ø   Gathering.    Historically, each partnership paid us a gathering fee which was typically insufficient to cover all of the gathering fees due to Atlas Pipeline. After the closing, pursuant to the terms of our contribution agreement with Atlas America, our gathering revenues and costs will net to $0. Please read “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement.”

RECENT DEVELOPMENTS

During the fourth quarter of 2006 and the first quarter of 2007, we and our investment partnerships plan to drill 3 wells to multiple pay zones, including the Marcellus Shale of Southwest Pennsylvania. The Marcellus Shale is a black, organic rich shale formation located at depths between 7,000 and 8,500 feet and ranges in thickness from 100 to 150 feet on our acreage in Fayette, Westmoreland and Greene Counties. We hold approximately 100,000 acres of prospective Marcellus acreage in these counties. Most of this acreage is held by production, meaning that it is covered by a continuing lease due to production from the property.

BUSINESS STRATEGY

The key elements of our business strategy are:

Expand our gas and oil production through continued growth in our sponsorship of investment partnerships.    We generate a significant portion of our revenue and net income from gas and oil production. We believe our program of sponsoring investment partnerships to exploit our acreage position provides us with a better economic return than if we were to drill the wells for our own account outside of our partnership management business. From October 1, 1999 through September 30, 2006, we sponsored 13 private and 9 public investment partnerships, and increased the annual amount of capital raised through investment partnerships by approximately 1170% from $15.7 million in fiscal

 


 

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1999 to $199.8 million in the twelve months ended September 30, 2006. We intend to continue to finance the growth in our drilling and production activities through growth in our investment partnerships.

Expand our fee-based revenue through continued growth in our sponsorship of investment partnerships.    We generate substantial revenue and net income from fees paid by the investment partnerships to us for acting as the managing general partner. As we continue to sponsor investment partnerships, we expect that our fee revenues from our drilling and operating agreements with our investment partnerships will continue to increase.

Expand operations through strategic acquisitions.    We continually evaluate opportunities to expand our operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our current areas of operation, as well as other regions of the United States.

Expand the number of our drilling locations in the Appalachian Basin through an active leasing program and joint ventures.    We have approximately 308,300 gross (294,800 net) undeveloped acres, principally in the Appalachian Basin, which we believe offer significant, low risk exploitation-type drilling opportunities. In addition, we are party to a joint venture agreement that encompasses approximately 212,000 acres in Tennessee and entitles us to drill 300 net wells through June 30, 2007. As of September 30, 2006, we had identified an inventory of approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage. Over the past three fiscal years, we drilled 1,864 gross (616 net) wells, 98% of which were successful in producing natural gas in commercial quantities. We intend to continue to develop this acreage, which, due to the generally high degree of step-out development success, should continue to add drilling locations to our inventory. Between September 2003 and September 2006, we added 137,600 net acres to our inventory. In addition, we will continue to pursue farmouts and joint venture opportunities from other oil and gas producers that can significantly add to our inventory of drilling locations.

Maintain control of operations.    We believe it is important to be the operator of wells in which we or our investment partnerships have an interest because we believe it will allow us to achieve operating efficiencies and control costs. Upon completion of this offering, we will continue to be the operator of approximately 85% of the properties in which we or our investment partnerships had a working interest at September 30, 2006.

Continue to manage our exposure to commodity price risk.    To limit our exposure to changing natural gas prices, we use financial hedges and physical hedges for a portion of our natural gas production. We use fixed price swaps as the mechanism for the financial hedging of our natural gas commodity prices. We enter into physical hedge contracts with Hess Corporation and other third-party marketers to which we sell gas.

COMPETITIVE STRENGTHS

We believe our competitive strengths favorably position us to execute our business strategy and to maintain and grow our distributions to unitholders. Our competitive strengths are:

Our partnership management business improves the economic rates of return associated with our gas and oil production activities. A well drilled, net to our equity interest, in our partnership management business will generate a higher rate of return to us than if we had taken a 100% economic interest in

 


 

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such well and drilled it outside of our partnership management business. For each well drilled in a partnership we receive an upfront 15% markup on the investors’ well construction and completion costs and an approximate $15,000 fixed administration and oversight fee. Further, we receive an approximate 7% incremental equity interest in each well, for which we do not make any corresponding capital contribution. Consequently, our economic interest in each well is significantly greater than our proportional contribution to the total cash costs which enhances our overall rate of return. Additionally, we receive monthly per well fees from the partnership for the life of each individual well, which also increases our rate of return.

Fee-based revenues from our investment partnerships provide a stable foundation for our distributions.    Our investment partnerships provide stable, fee-based revenues which diminish the influence of commodity price fluctuations on our cash flows. Our fees for managing our investment partnerships accounted for 18% of our segment margin in the twelve months ended September 30, 2006, 20% of our segment margin in fiscal 2005, 21% in fiscal 2004 and 15% in fiscal 2003. In addition, because our investment partnerships reimburse us on a cost-plus basis for drilling capital expenses, we are partially protected against increases in drilling costs.

We are one of the leading sponsors of tax-advantaged investment partnerships.    Through our predecessors, we have sponsored limited and general partnerships to raise funds from investors to finance our development drilling activities since 1968, and we believe that we are one of the leading sponsors of such investment partnerships in the country. We believe that our lengthy association with many of the broker-dealers that act as placement agents for our investment partnerships provide us with a competitive advantage over entities with similar operations. We also believe that our sponsorship of investment partnerships has allowed us to generate attractive returns on drilling, operating and production activities.

We have a high quality, long-lived reserve base.    Our natural gas properties are located principally in the Appalachian Basin and are characterized by long-lived reserves, a high success rate in drilling and completing wells, favorable pricing for our production and readily available transportation. For the twelve month period ended September 30, 2006, we produced 25,924 Mcfe/d to our interest, which resulted in an average reserve life of approximately 18 years based on our proved reserves at March 31, 2006. Moreover, because our production in the Appalachian Basin is located near markets in the northeast United States, we believe we will generally receive a premium over quoted prices on the NYMEX for the natural gas we produce. This premium has ranged between $0.36 to $0.41 per Mcf during the past three fiscal years.

We have a significant inventory of future drilling locations and undeveloped acreage.    We have 294,800 net undeveloped acres relative to 221,400 net developed acres. We believe our inventory of undeveloped acreage, as well as identified drilling opportunities, will permit us to sustain our projected levels of drilling activity for several years without additions to our property holdings. Further, we believe that the size of our undeveloped acreage position relative to our developed acreage position provides us with organic opportunities to significantly expand our production base.

We have long-standing relationships with regional drilling contractors, service providers and equipment vendors.    We have drilled and operated wells in the Appalachian Basin since 1968. Over this extended period of time, we have provided reliable, consistent and repeated business to small regional drilling contractors, service providers and equipment vendors which has resulted in unique, long-standing relationships that we believe provide us with a competitive advantage over other Appalachian exploration and production companies.

 


 

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Our relationship with Atlas Pipeline gives us reliable access to the markets we serve and reduces capital expenditures we would otherwise incur.    We transport our natural gas through gathering lines operated by Atlas Pipeline (NYSE: APL), for which an affiliate of Atlas America acts as general partner. Atlas Pipeline’s 1,500 miles of gathering systems in the Appalachian Basin are situated throughout the areas in which we drill other than Tennessee, are readily accessible by us, and are connected to major regional and interstate utility pipelines. Atlas Pipeline is required to extend its gathering system to our well if we extend sales and flow lines to within 1,000 feet of the gathering system, while we must connect to the gathering system any well we drill and operate that is within 2,500 feet of it. Our relationship with Atlas Pipeline permits us to have reliable access to the natural gas markets we serve and significantly reduces the capital we would otherwise expend to connect our wells to a pipeline system in order to transport the gas to those markets.

Through our manager, we have significant engineering, geologic and management experience in our core Appalachian Basin operating area.    Our manager’s technical team of 16 geologists and engineers has extensive industry experience, principally in the Appalachian Basin. We believe that we have been one of the most active drillers in our core operating area and, as a result, that we have accumulated extensive geological and geographical knowledge about the area.

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 September 30, 2006, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.36 per MMBtu. In addition, most of our natural gas production has a high Btu content, resulting in an additional premium to NYMEX natural gas prices.

During the first several years of production, Appalachian Basin wells generally experience higher initial production rates and decline rates which are followed by an extended period of significantly lower production rates and decline rates.

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

GAS AND OIL PRODUCTION

As of September 30, 2006, we owned interests in 7,047 gross wells, principally in the Appalachian Basin, of which we operated 5,978. Over the past three fiscal years we have drilled 1,864 gross (616 net) wells, 98% of which were successful in producing natural gas in commercial quantities.

In September 2004, we expanded our operations into Tennessee through a joint venture with Knox Energy that gives us an exclusive right to drill up to 300 wells before June 30, 2007 on approximately

 


 

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212,000 acres owned by Knox Energy. Please read “—Tennessee Joint Venture Agreement.” As of September 30, 2006, we had identified approximately 400 proved undeveloped drilling locations and approximately 2,700 additional potential drilling locations on our acreage and our Tennessee joint venture acreage.

The following table sets forth, for the periods indicated, revenues, net production of oil and natural gas sold, average sales price per unit of oil and natural gas and costs and expenses associated with the production of natural gas and oil. Revenues shown in this table do not reflect the impact of any hedges for the periods indicated in order to show revenues on a consistent basis for the periods presented.

 

     For the fiscal year ended
September 30,
  

For the

three

months

ended

December 31,

2005

  

For the

nine months
ended
September 30,
2006

            2004                2005            
     (dollars in thousands, except where indicated)

Sales:

           

Natural gas

           

Revenue(1)

   $ 42,532    $ 55,376    $ 21,851    $ 59,332

Production sold (Mcf/d)

     19,905      20,892      21,468      24,064

Average sales price per Mcf(1)

   $ 5.84    $ 7.26    $ 11.06    $ 9.03

Oil

           

Revenue

   $ 5,947    $ 8,039    $ 2,227    $ 7,323

Production sold (Bbl/d)

     495      433      431      415

Average sales price per Bbl

   $ 32.85    $ 50.91    $ 56.13    $ 64.59

Costs and expenses:

           

Production costs per Mcfe

   $ 0.87    $ 0.95    $ 1.10    $ 1.42

Depletion per Mcfe

   $ 1.22    $ 1.42    $ 2.01    $ 2.04

(1)   Excludes the effects of any hedges and price risk management activities.

PRODUCTIVE WELLS

The following table sets forth information as of March 31, 2006, the date of our most recent reserve report, regarding productive natural gas and oil wells in which we have a working interest. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, directly or through our ownership interests in investment partnerships, and net wells are the sum of our fractional working interests in gross wells, based on the percentage interest we own in the investment partnership that owns the well.

 

     Number of
productive wells
      Gross(1)    Net(1)

Oil wells

   491    335

Gas wells

   5,623    2,766
         

Total

   6,114    3,101
         

(1)   Includes our proportionate interest in wells owned by 91 investment partnerships for which we serve as managing general partner and various joint ventures. Does not include royalty or overriding interests in 632 wells.

 


 

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DEVELOPED AND UNDEVELOPED ACREAGE

The following table sets forth information about our developed and undeveloped natural gas and oil acreage as of September 30, 2006. The information in this table includes our proportionate interest in acreage owned by investment partnerships. The table does not include the approximately 212,000 acres in Tennessee covered by our joint venture with Knox Energy because we do not own this acreage.

 

     Developed acreage(1)    Undeveloped
acreage(2)
      Gross(3)    Net(4)    Gross(3)    Net(4)

Arkansas

   2,560    403    0    0

Kansas

   160    20    0    0

Kentucky

   924    462    9,060    4,530

Louisiana

   1,819    206    0    0

Mississippi

   40    3    0    0

Montana

   0    0    2,650    2,650

New York

   20,517    15,053    38,094    38,094

North Dakota

   639    96    0    0

Ohio

   114,226    95,027    37,811    34,329

Oklahoma

   4,323    468    0    0

Pennsylvania

   104,561    104,561    209,666    209,666

Tennessee

   5,200    4,265    92    92

Texas

   4,520    329    0    0

West Virginia

   1,078    539    10,806    5,403

Wyoming

   0    0    80    80
                   

Total

   260,567    221,432    308,259    294,844
                   

(1)   Developed acres are acres spaced or assigned to productive wells.
(2)   Undeveloped acres are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas or oil, regardless of whether such acreage contains proved reserves.
(3)   A gross acre is an acre in which we own a working interest. The number of gross acres is the total number of acres in which we own a working interest.
(4)   Net acres is the sum of the fractional working interests owned in gross acres. For example, a 50% working interest in an acre is one gross acre but is 0.50 net acre.

The leases for our developed acreage generally have terms that extend for the life of the wells, while the leases on our undeveloped acreage have terms that vary from less than one year to five years. We paid rentals of approximately $577,000 in fiscal 2005 and $735,000 for the twelve months ended September 30, 2006 to maintain our leases.

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

 


 

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

DRILLING ACTIVITY

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

 

    Development wells   Exploratory wells
    Productive   Dry   Productive   Dry
     Gross(1)   Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2)   Gross(1)   Net(2)

Nine months ended September 30, 2006

  502.0   169.4   3.0   1.1   —     —     —     —  

Three months ended December 31, 2005

  192.0   64.1   —     —     —     —     —     —  

Fiscal year 2005

  644.0   210.0   18.0   6.3   —     —     —     —  

Fiscal year 2004

  493.0   160.5   11.0   3.8   —     —     1.0   1.0

Fiscal 2003

  295.0   92.9   1.0   0.3   —     —     —     —  

(1)   Includes the number of physical wells in which we hold any working interest, regardless of our percentage interest.
(2)   Includes (i) our percentage interest in wells in which we have a direct ownership interest and (ii) with respect to wells in which we have an indirect ownership interest through our investment partnerships, our percentage interest in the wells based on our percentage interest in our investment partnerships and not those of the other partners in our investment partnerships.

INVESTMENT PARTNERSHIPS

We generally fund our drilling activities through sponsorship of tax-advantaged investment partnerships. Accordingly, the amount of development activities we undertake depends in part upon our ability to obtain investor subscriptions to the partnerships. We raised $199.8 million in the twelve months ended September 30, 2006 through our investment partnerships. During the twelve months ended September 30, 2006, our investment partnerships invested $206.5 million in drilling and completing wells, of which we contributed $55.0 million. During fiscal 2005, our investment partnerships invested $157.0 million in drilling and completing wells, of which we contributed $57.3 million.

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

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

 


 

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

The following table sets forth, as of September 30, 2006, information with respect to our investment partnerships formed since January 1, 2001. In addition to these partnerships, we also manage 75 other investment partnerships which we acquired or formed before January 1, 2001.

 

Partnership   Investor
capital
  Our capital   Total capital  

Date

opera-

tions

began

  Gross wells   Net wells  

Cumula-

tive

gather-

ing fees

  Cumulative
operator’s
charges
 

Cumulative

reimburse-

ment of

general

and
adminis-

trative
overhead

          Oil   Gas   Dry   Oil   Gas   Dry      

Atlas America—Series 21-A

  $ 12,510,713   $ 4,535,799   $ 17,046,512   05/15/01   0   68   0   0   62.50   0.00   $ 739,790   $ 1,533,608   $ 276,338

Atlas America—Series 21-B

    17,411,825     6,442,761     23,854,586   09/19/01   0   89   2   0   84.05   1.00     961,756     1,889,649     332,262

Atlas America—Public #10

    21,281,170     7,227,432     28,508,602   12/31/01   0   107   3   0   103.15   3.00     1,341,076     1,939,762     387,027

Atlas America—Series 22

    10,156,375     3,481,591     13,637,966   05/31/02   0   51   1   0   49.55   1.00     622,477     895,440     173,201

Atlas America—Series 23

    9,644,550     3,214,850     12,859,400   09/30/02   0   47   1   0   47.00   1.00     579,777     784,841     159,900

Atlas America—Public #11-2002

    31,178,145     13,250,300     44,428,445   12/31/02   0   167   0   0   160.50   0.00     1,483,486     2,766,556     482,613

Atlas America—Series #24-2003(A)

    14,363,955     4,985,035     19,348,990   05/31/03   0   76   0   0   69.50   0.00     544,270     993,350     179,981

Atlas America—Series #24-2003(B)

    20,542,850     7,602,890     28,145,740   08/29/03   0   121   1   0   113.00   1.00     930,751     1,610,220     253,350

Atlas America—Public #12-2003

    40,168,500     17,285,400     57,453,900   12/31/03   0   226   6   0   214.25   1.00     1,488,079     2,385,562     436,538

Atlas America—Series #25-2004(A)

    27,601,053     12,086,800     39,687,853   05/31/04   0   137   4   0   130.80   4.00     1,233,265     1,169,355     195,653

Atlas America—Series #25-2004(B)

    31,531,035     15,238,800     46,769,835   08/31/04   0   171   4   0   153.40   4.00     820,151     1,353,375     198,008

Atlas America—Public #14-2004

    52,506,570     23,677,700     76,184,270   11/15/04   0   256   11   0   233.55   11.00     1,075,334     1,631,341     222,336

Atlas America—Public #14-2005(A)

    69,674,900     26,374,800     96,049,700   06/17/05   0   338   5   0   315.49   5.00     1,386,803     1,392,565     193,191

Atlas America—Series #26-2005

    34,886,465     13,647,700     48,534,165   09/16/05   0   142   2   0   132.31   2.00     371,529     390,318     54,394

Atlas America—Public #15-2005(A)

    52,245,720     17,793,200     70,038,920   12/31/05   0   187   1   0   181.50   1.00     414,816     327,267     55,969

Atlas America—Public #15-2006(B)

    147,513,130     32,815,300     180,328,430   09/12/06   0   243   1   0   228.18   1.00     0     0     0

TENNESSEE JOINT VENTURE AGREEMENT

We have a drilling and operating agreement, dated September 15, 2004, with Knox Energy which creates an Area of Mutual Interest, which we refer to as the AMI, covering approximately 212,000 acres in Anderson, Campbell, Scott and Morgan counties in Tennessee. The agreement gives us the exclusive right to propose and drill up to 300 net wells through June 30, 2007. At the option of Knox Energy, the agreement may be extended through June 30, 2009, giving us the right to propose and drill an additional 200 net wells. We are the named operator of all the wells drilled under the agreement and pay Knox

 


 

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Energy our proportionate share of a site fee of $4,000 and a well completion fee of $2,000. If the

agreement is extended, the site fee and well completion fee increase to $5,000 and $2,500, respectively. Knox Energy has the right to participate on well-by-well basis in up to 50% of the working interest in each well drilled. Further, Knox Energy receives a 1/64th overriding royalty interest for each well it fully

participates, and a 1/32nd overriding royalty interest for wells in which it chooses not to participate. For wells in which Knox Energy chooses to participate, but at less than a 50% working interest, it receives a proportionate overriding royalty interest. Each party pays its proportionate share of well construction costs, while Knox Energy is also allocated its proportionate share general and administrative costs for each well in which it participates. As part of the agreement, we must drill a minimum number of wells on certain acreage within the AMI. As of September 30, 2006, we are in compliance with our minimum well commitments and have drilled 114 net wells under the agreement.

NATURAL GAS AND OIL RESERVES

The following tables summarize information regarding our estimated proved natural gas and oil reserves as of September 30, 2003, 2004 and 2005, December 31, 2005 and March 31, 2006. Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The estimated reserves include reserves attributable to our direct ownership interests in oil and gas properties as well as the reserves attributable to our percentage interests in the oil and gas properties owned by investment partnerships in which we own partnership interests. All of the reserves are located in the United States. We base these estimated proved natural gas and oil reserves and future net revenues of natural gas and oil reserves upon reports prepared by Wright & Company, Inc., energy consultants. A summary of the reserve report related to our estimated proved reserves at March 31, 2006 is included in this prospectus as Appendix C. In accordance with SEC guidelines, we make the standardized measure and PV-10 estimates of future net cash flows from proved reserves using natural gas and oil sales prices in effect as of the dates of the estimates which are held constant throughout the life of the properties. We based our estimates of proved reserves upon the following weighted average prices as of the dates indicated:

 

     September 30,   

December 31,

2005

  

March 31,

2006

      2003    2004    2005      

Natural gas (per Mcf)

   $ 4.96    $ 6.91    $ 14.75    $ 10.84    $ 8.04

Oil (per Bbl)

   $ 26.00    $ 46.00    $ 63.29    $ 57.54    $ 63.52

Reserve estimates are imprecise and may change as additional information becomes available. Furthermore, estimates of natural gas and oil reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of natural gas and oil that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserve reports of other engineers might differ from the reports of our consultants, Wright & Company. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of this estimate. Future prices received from the sale of natural gas and oil may be different from those estimated by Wright & Company in preparing its reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, the reserves set forth in the following tables ultimately may not be produced and the

 


 

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proved undeveloped reserves may not be developed within the periods anticipated. Please read “Risk factors—Risks Inherent in Our Business.” You should not construe the estimated PV-10 and standardized measure values as representative of the current or future fair market value of our proved natural gas and oil properties. PV-10 and standardized measure values are based upon projected cash inflows, which do not provide for changes in natural gas and oil prices or for the escalation of expenses and capital costs. The meaningfulness of these estimates depends upon the accuracy of the assumptions upon which they were based.

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

 

    Proved natural gas and oil reserves for
Atlas America E&P Operations at
  Proved natural gas and
oil reserves for Atlas
Energy Resources
at March 31, 2006
    September 30,  

December 31,

2005

 
     2003   2004   2005    

Natural gas reserves (Mmcf):

         

Proved developed reserves

    87,760     95,788     104,786     108,674     107,889

Proved undeveloped reserves(1)

    45,533     46,345     53,241     49,250     50,221
                             

Total proved reserves of natural gas

    133,293     142,133     158,027     157,924     158,110
                             

Oil reserves (Mbbl):

         

Proved developed reserves

    1,825     2,126     2,116     2,122     2,018

Proved undeveloped reserves

    30     149     143     135     120
                             

Total proved reserves of oil

    1,855     2,275     2,259     2,257     2,138
                             

Total proved reserves (MMcfe)

    144,423     155,782     171,581     171,466     170,938
                             

PV-10 estimate of cash flows of proved reserves (in thousands)(2):

         

Proved developed reserves

  $ 164,617   $ 265,516   $ 617,445   $ 465,459   $ 349,741

Proved undeveloped reserves

    26,802     54,863     228,206     131,678     62,632
                             

Total PV-10 estimate(3)

  $ 191,419   $ 320,379   $ 845,651   $ 597,137   $ 412,373
                             

Standardized measure of discounted future cash flows (in thousands)(2)(3)

  $ 144,351   $ 232,998   $ 606,697   $ 429,272   $ 412,373
                             

(1)   Our ownership in these reserves is subject to reduction as we generally contribute leasehold acreage associated with our proved undeveloped reserves to our investment partnerships in exchange for an approximate 30% equity interest in these partnerships which effectively will reduce our ownership interest in these reserves from 100% to 30% as we make these contributions.
(2)   Amounts shown for September 30, 2003, 2004 and 2005 and December 31, 2005 reflect values for Atlas America E&P Operations, which pays income taxes. Amounts shown for March 31, 2006 reflect values for our reserves on a pro forma basis to reflect the contribution of assets of Atlas America to us at the closing of this offering. Since we are a limited liability company that allocates our taxable income to our unitholders, no provision for federal or state income taxes has been included in the March 31, 2006 calculation of standardized measure which is, therefore, the same as the PV-10 value. Amounts include physical hedges but not financial hedging transactions. We estimate that if natural gas prices decline by $1.00 per Mcf, then the PV-10 value of our proved reserves as of March 31, 2006 would decrease from $412.4 million to $348.7 million. For a description of our hedging transactions, please read “—Natural Gas Hedging.”

 


 

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

 

     Atlas America E&P Operations as of      Pro forma
Atlas Energy
Resources as
of March 31,
2006
     September 30,    

December 31,

2005

   
      2003     2004     2005      

PV-10 value

   $ 191,419     $ 320,379     $ 845,651     $ 597,137     $ 412,373

Income tax effect

     (47,068 )     (87,381 )     (238,954 )     (167,865 )     —  
                                      

Standardized measure

   $ 144,351     $ 232,998     $ 606,697     $ 429,272     $ 412,373
                                      

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.

NATURAL GAS SALES

We have a natural gas supply agreement with Hess Corporation which is valid through March 31, 2009. Subject to certain exceptions, Hess Corporation has a last right of refusal to buy all of the natural gas produced and delivered by us and our affiliates, including our investment partnerships, at certain delivery points with the facilities of:

 

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

 

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

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

 

Ø   natural gas we sell to Warren Consolidated, an industrial end-user and direct delivery customer;

 

Ø   natural gas that at the time of the agreement was already dedicated for the life of the well to another buyer;

 

Ø   natural gas that is produced by a company which was not an affiliate of ours at the time of the agreement;

 

Ø   natural gas sold through interconnects established subsequent to the agreement;

 

Ø   natural gas that is delivered to interstate pipelines or local distribution companies other than those described above; and

 

Ø   natural gas that is produced from wells operated by a third-party or subject to an agreement under which a third-party was to arrange for the gathering and sale of the natural gas.

Based on the most recent monthly production data available to us as of September 30, 2006, we anticipate that we and our affiliates, including our investment partnerships, will sell approximately 30% of our natural gas production during the twelve months ending December 31, 2007 under the Hess Corporation agreement. The agreement requires the parties to negotiate a new pricing arrangement at each annual delivery point. If, at the end of any applicable period, the parties cannot agree to a new price for any delivery point, then we may solicit offers from third parties to buy the natural gas for that delivery point. If Hess Corporation does not match this price, then we may sell the natural gas to the

 


 

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third party. We market the remainder of our natural gas, which is principally located in the Fayette County, PA area, primarily to Colonial Energy, Inc., UGI Energy Services, and others. See “—Major Customers.” During the twelve months ended September 30, 2006, we received an average of $9.50 per Mcf of natural gas, compared to $7.26 per Mcf in fiscal 2005, $5.84 per Mcf in fiscal 2004 and $4.92 per Mcf in fiscal 2003.

We expect that natural gas produced from our wells drilled in areas of the Appalachian Basin other than those described above will be primarily tied to the spot market price and supplied to:

 

Ø   gas marketers;

 

Ø   local distribution companies;

 

Ø   industrial or other end-users; and/or

 

Ø   companies generating electricity.

CRUDE OIL SALES

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

DISMANTLEMENT, RESTORATION, RECLAMATION AND ABANDONMENT COSTS

When we determine that a well is no longer capable of producing natural gas or oil in economic quantities, we must dismantle the well and restore and reclaim the surrounding area before we can abandon the well. We contract these operations to independent service providers to whom we pay a fee. The contractor will also salvage the equipment on the well, which we then sell in the used equipment market. Under the partnership agreements of our investment partnerships, which own the majority of our wells, we are allocated abandonment costs in proportion to our partnership interest (generally between 27% and 35%) and are allocated between 65% and 100% of the salvage proceeds. As a consequence, we generally receive proceeds from salvaged equipment at least equal to, and typically exceeding, our share of the related costs.

NATURAL GAS HEDGING

Pricing for natural gas and oil production has been volatile and unpredictable for many years. To limit our exposure to changing natural gas prices, we use financial and physical hedges for a portion of our natural gas production. Through our hedges, we seek to provide a measure of stability in the volatile environment of natural gas prices. The financial hedges may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. The futures contracts are commitments to purchase or sell natural gas at future dates and generally cover one-month periods for up to 36 months in the future. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we have a management committee to assure that all financial trading is done in compliance with our hedging policies and procedures. We do not intend to contract for positions that we cannot offset with actual production. As of November 1, 2006, we had financial hedges and physical hedges in place for approximately 77% of our expected production for the twelve months ending December 31, 2007.

 


 

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Hess Corporation and other third-party marketers to which we sell gas, such as Colonial Energy, Inc. and UGI Energy Services, also use NYMEX-based financial instruments to hedge their pricing exposure and make price hedging opportunities available to us. We enter into physical hedge transactions which are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We generally limit these arrangements to much smaller quantities than those projected to be available at any delivery point. The price paid by Hess Corporation, Colonial Energy, Inc., UGI Energy Services, and any other third-party marketers for certain volumes of natural gas sold under these sales agreements may be significantly different from the underlying monthly spot market value. Fixed prices are defined as the price we have established with the related purchaser and are not subject to change in the future. For a description of our financial hedges, please read “Management’s discussion and analysis of financial condition and results of operations—Quantitative and Qualitative Disclosures About Market Risk.”

NATURAL GAS GATHERING

We conduct our natural gas transportation and processing operations through Atlas America’s affiliate, Atlas Pipeline. Atlas Pipeline owns approximately 1,500 miles of gathering systems located in eastern Ohio, western New York and western Pennsylvania serving approximately 5,100 wells.

Upon completion of this offering, we will become a party to an existing omnibus agreement between Atlas America and Atlas Pipeline which sets forth the obligations that we, Atlas America and Atlas Pipeline will have to connect wells to the Atlas Pipeline gathering systems and that we will have to provide consultation services in the construction of new gathering systems or the extension of existing systems. Because, upon closing, we will own substantially all of Atlas America’s natural gas and oil development and production business, we will be primarily liable under the omnibus agreement, and Atlas America will be secondarily liable as a guarantor of our performance.

We will also become a party to an existing master natural gas gathering agreement between Atlas America and Atlas Pipeline pursuant to which Atlas Pipeline will gather substantially all of the natural gas from wells operated by us. Atlas America will assume all of our obligations under this agreement to pay gathering fees to Atlas Pipeline; we will agree to pay Atlas America the gathering fees we receive from our investment partnership and fees associated with production to our interest. We will also be party to three other gas gathering agreements with Atlas Pipeline relating to certain wells we will own directly after closing and wells owned by third parties unrelated to us or our investment partnerships.

Omnibus agreement

Well connections.    We will be required to construct, at our sole cost and expense, up to 2,500 feet of small diameter (two inches or less) sales or flow lines from the wellhead of any well we drill and operate to a point of connection to Atlas Pipeline’s gathering systems. Where we have extended sales and flow lines to within 1,000 feet of one of Atlas Pipeline’s gathering systems, we may require Atlas Pipeline to extend its system to connect to that well. With respect to other wells that are more than 2,500 feet from Atlas Pipeline’s gathering systems, Atlas Pipeline will have the right, at its cost and expense, to extend its gathering system to within 2,500 feet of the well and to require us, at our cost and expense, to construct up to 2,500 feet of flow line to connect to the gathering system extension. If Atlas Pipeline elects not to exercise its right to extend its gathering systems, we may connect a well to a natural gas gathering system owned by a third party or to any other delivery point; however, Atlas Pipeline will have the right to assume the cost of construction of the necessary flow lines, which then become its property and part of its gathering systems.

 


 

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Consulting services.    The agreement also requires us to assist Atlas Pipeline in seeking to identify existing gathering systems for possible acquisition and provide consulting services in evaluating and making a bid for these systems. We will also agree that any gathering system we identify as a potential acquisition will first be offered to Atlas Pipeline. Atlas Pipeline will have 30 days to determine whether it wants to acquire the identified system and advise us of its intent. If Atlas Pipeline intends to acquire the system, it will have an additional 60 days to complete the acquisition. If Atlas Pipeline does not complete the acquisition, or advises us that it does not intend to acquire the system, then we may do so.

Gathering system construction.    We will provide Atlas Pipeline with construction management services if Atlas Pipeline determines to expand one or more of its gathering systems. We will be entitled to reimbursement for our costs, including an allocable portion of employee salaries, in connection with our construction management services.

The omnibus agreement has no specified term but will terminate if Atlas Pipeline Partners GP is removed as the general partner of Atlas Pipeline without cause.

Natural gas gathering agreements

Under the master natural gas gathering agreement, we will be obligated to pay Atlas Pipeline a fee for gathering our natural gas. As described in “Certain relationships and related transactions—Agreements Governing the Transactions—The contribution agreement,” Atlas America will assume our obligations under this agreement to pay the gathering fees to Atlas Pipeline, and we will agree to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest. However, Atlas America must pay gathering fees owed to Atlas Pipeline from its own resources regardless of the amounts we pay to it.

Under the master natural gas gathering agreement, Atlas Pipeline charges gathering fees as follows:

 

Ø   for natural gas from our well interests, other than those of our investment partnerships, that were connected to Atlas Pipeline’s gathering systems at February 2, 2000, the greater of $0.40 per Mcf or 16% of the gross sales price of the natural gas transported;

 

Ø   for (i) natural gas from well interests allocable to our investment partnerships that drilled or drill wells on or after December 1, 1999 that are connected to the gathering systems (ii) natural gas from our well interests, other than those of our investment partnerships, that are connected to the gathering systems after February 2, 2000, and (iii) well interests allocable to third parties in wells connected to the gathering systems at February 2, 2000, the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported; and

 

Ø   for natural gas from well interests we operate and drilled after December 1, 1999 that are connected to a gathering system that is not owned by Atlas Pipeline and for which Atlas Pipeline assumes the cost of constructing the connection to that gathering system, an amount equal to the greater of $0.35 per Mcf or 16% of the gross sales price of the natural gas transported, less the gathering fee charged by the other gathering system.

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

The gathering fees payable to Atlas Pipeline generally exceed the amount we receive from our investment partnerships for gathering services. See “Risk factors—Risks Inherent in Our Business—If Atlas America

 


 

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fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we would have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources.”

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

 

Ø   Atlas America subsidiaries which will become our subsidiaries at closing are obligated under two agreements, relating to wells located in southeastern Ohio which were originally acquired from Kingston Oil Corporation and wells located Fayette County, Pennsylvania which were originally acquired from American Refining and Exploration Company, to pay Atlas Pipeline gathering fees of $0.80 per Mcf. These wells are owned directly by the subsidiaries and, accordingly, Atlas America will not assume any part of our obligation to pay the gathering fees to Atlas Pipeline under these agreements.

 

Ø   Atlas America subsidiaries which will become our subsidiaries at closing are obligated under another agreement, which covers wells owned by third parties unrelated to us and our investment partnerships, to pay Atlas Pipeline gathering fees that range between $0.20 and $0.29 per Mcf or between 10% to 16% of the weighted average sales price. The gathering fees payable under this agreement are a direct pass-through of the gathering fees we will receive from the third party wells. Accordingly, Atlas America will not assume any part of our obligation to pay the gathering fees to Atlas Pipeline under this agreement, and will be removed as an obligor under it.

AVAILABILITY OF OIL FIELD SERVICES

We contract for drilling rigs and purchase goods and services necessary for the drilling and completion of wells from a number of drillers and suppliers, none of which supplies a significant portion of our annual needs. During fiscal 2005 and the twelve months ended September 30, 2006, we faced no shortage of these goods and services. Over the past three years, we and other oil and natural gas companies have experienced higher drilling and operating costs. We cannot predict the duration or stability of the current level of supply and demand for drilling rigs and other goods and services required for our operations with any certainty due to numerous factors affecting the energy industry, including the demand for natural gas and oil.

MAJOR CUSTOMERS

Our natural gas is sold under contract to various purchasers. For the years ended September 30, 2003, 2004 and 2005 and the twelve months ended September 30, 2006, gas sales to Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 20%, 13%, 12% and 10%, respectively, of our total revenues. No other single customer accounted for more than 10% of our total revenues during these periods.

COMPETITION

The energy industry is intensely competitive in all of its aspects. We operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through our investment partnerships, contracting for drilling equipment and securing trained personnel. We also compete with the exploration and production divisions of public utility companies for natural gas and oil property acquisitions. Competition is intense for the acquisition of leases considered favorable for the

 


 

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development of natural gas and oil in commercial quantities. Our competitors may be able to pay more for natural gas and oil properties and to evaluate, bid for and purchase a greater number of properties than our financial or personnel resources permit. Furthermore, competition arises not only from numerous domestic and foreign sources of natural gas and oil but also from other industries that supply alternative sources of energy. Product availability and price are the principal means of competition in selling oil and natural gas.

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

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

MARKETS

The availability of a ready market for natural gas and oil and the price obtained, depends upon numerous factors beyond our control, as described in “Risk factors—Risks Inherent in Our Business.” Product availability and price are the principal means of competition in selling oil and natural gas. During the twelve months ended September 30, 2006 and fiscal 2005, 2004 and 2003, we did not experience problems in selling our natural gas and oil, although prices have varied significantly during those periods.

NATURAL GAS AND OIL LEASES

The typical natural gas and oil lease agreement provides for the payment of royalties to the mineral owner for all natural gas and oil produced from any well(s) drilled on the leased premises. In the Appalachian Basin this amount is typically 1/8th (12.5%) resulting in a 87.5% net revenue interest to us for most leases directly acquired by us. In certain instances, this royalty amount may increase to 1/6th (16.66%) when leases are taken from larger landowners or mineral owners such as coal and timber companies.

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

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

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

 


 

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SEASONAL NATURE OF BUSINESS

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

ENVIRONMENTAL MATTERS AND REGULATION

General

Our operations are subject to comprehensive and stringent federal, state and local laws and regulations governing, among other things, where and how we install wells, how we handle wastes from our operations and the discharge of materials into the environment. Our operations will be subject to the same environmental laws and regulations as other companies in the natural gas and oil industry. Among other requirements and restrictions, these laws and regulations:

 

Ø   require the acquisition of various permits before drilling commences;

 

Ø   require the installation of expensive pollution control equipment;

 

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

 

Ø   limit or prohibit drilling activities on lands lying within or, in some cases, adjoining wilderness, wetlands and other protected areas;

 

Ø   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;

 

Ø   impose substantial liabilities for pollution resulting from our operations; and

 

Ø   with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of natural gas and oil production below the rate that would otherwise be possible. The regulatory burden on the natural gas and oil industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently enact new, and revise existing, environmental laws and regulations, and any new laws or changes to existing laws that result in more stringent and costly waste handling, disposal and clean-up requirements for the natural gas and oil industry could have a significant impact on our operating costs. We believe that our operations on the whole substantially comply with all currently applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict how environmental laws and regulations that may take effect in the future may impact our properties or operations. For the years ended September 30, 2005 and 2006, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this prospectus, we are not aware of

 


 

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any environmental issues or claims that will require material capital expenditures during the remainder of 2006 or in 2007, or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the natural gas and oil exploration and production industry include the following:

National Environmental Policy Act

Natural gas and oil exploration and production activities on federal lands are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Department of Interior, to evaluate major federal agency actions having the potential to significantly 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 our proposed exploration and production activities on federal lands require governmental permits, many of which are subject to the requirements of NEPA. This process has the potential to delay the development of natural gas and oil projects.

Waste Handling

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

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

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or legality of conduct, on persons who are considered under the statute to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 


 

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Our operations are, in many cases, conducted at properties that have been used for natural gas and oil exploitation and production for many years. Although we believe Atlas America utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under the properties owned or leased by us or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

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

Air Emissions

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

OSHA and Other Regulations

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

Other Laws and Regulation

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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 our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our 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 our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

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

Drilling and Production

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

 

Ø   the location of wells;

 

Ø   the method of drilling and casing wells;

 

Ø   the surface use and restoration of properties upon which wells are drilled;

 

Ø   the plugging and abandoning of wells; and

 

Ø   notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of natural gas and oil properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose requirements

 


 

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regarding the ratability of production. These laws and regulations may limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

Natural Gas Regulation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission. Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. The Federal Energy Regulatory Commission’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

State Regulation

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

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

LITIGATION

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, including spills of oil or releases of pollutants, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings pending against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject as to which specific disclosure would be required under the securities laws.

 


 

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Management

OUR BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

Upon completion of this offering, our board of directors will consist of seven directors, including the director nominees named below who have consented to serve as directors, three of whom will satisfy the independence standards of the New York Stock Exchange.

Our current directors, and nominees, and executive officers are as follows:

 

Name    Age    Title

Edward E. Cohen

   67    Chairman of the Board and Chief Executive Officer

Jonathan Z. Cohen

   36    Vice Chairman of the Board

Richard D. Weber

   43    President, Chief Operating Officer and Director

Matthew A. Jones

   45    Chief Financial Officer and Director

Nancy J. McGurk

   50    Chief Accounting Officer

Lisa Washington

   39    Chief Legal Officer and Secretary

Walter C. Jones

   43    Director Nominee

Ellen F. Warren

   50    Director Nominee

Bruce M. Wolf

   58    Director Nominee

Edward E. Cohen has been our Chairman of the Board and Chief Executive Officer since our formation in 2006 and Chairman of the Board and Chief Executive Officer of Atlas Energy Management since its formation in 2006. He has been the Chief Executive Officer and President of Atlas America since its formation in September 2000. He 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. In addition, Mr. Cohen has been Chairman of the managing board of Atlas Pipeline Partners GP, LLC, the general partner of Atlas Pipeline Partners, L.P., since its formation in 1999, Chairman of the Board and Chief Executive Officer of Atlas Pipeline Holdings GP, LLC, the general partner of Atlas Pipeline Holdings, L.P., since its formation in January 2006, Chairman of the Board of Resource Capital Corp. (a publicly-traded real estate investment trust) since its formation in September 2005, a director of TRM Corporation (a publicly-traded consumer services company) since 1998 and Chairman of the Board of Brandywine Construction & Management, Inc. (a property management company) since 1994. Mr. Cohen is the father of Jonathan Z. Cohen.

Jonathan Z. Cohen has been Vice Chairman of the Board since our formation in 2006 and Vice Chairman of Atlas Energy Management since its formation in 2006. He has been the Vice Chairman of Atlas America since its formation in September 2000. He 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 Vice Chairman of the managing board of Atlas Pipeline Partners GP since its formation in 1999, Vice Chairman of the Board of Atlas Pipeline Holdings GP since its formation in January 2006, Chief Executive Officer, President and a director of Resource Capital Corp. since its formation in 2005 and a trustee and secretary of RAIT Investment Trust (a publicly-traded real estate investment trust) since 1997 and its Vice Chairman since 2003. Mr. Cohen is a son of Edward E. Cohen.

Richard D. Weber has been our President, Chief Operating Officer and a director since our formation in 2006 and President, Chief Operating Officer and a director of Atlas Energy Management since its formation in 2006. Mr. Weber served from June 1997 until March 2006 as Managing Director and

 


 

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Group Head of the Energy Group of KeyBanc Capital Markets, a division of KeyCorp, and its predecessor, McDonald & Company Securities, Inc. As part of his duties, he oversaw the bank’s activities with oil and gas producers, pipeline companies and utilities. He has a particular expertise in the Appalachian Basin, where he led over 40 transactions, including the IPOs of Atlas America and Atlas Pipeline and the sale of Viking Resources Corporation to Atlas America.

Matthew A. Jones has been our Chief Financial Officer and a director since our formation and Chief Financial Officer of Atlas Energy Management since its formation. He has been the Chief Financial Officer of Atlas America and of Atlas Pipeline Partners GP since March 2005. He 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, which we refer to as FBR, concluding as Managing Director. Mr. Jones worked in FBR’s Energy Investment Banking Group from 1999 to 2005 and in FBR’s Specialty Finance and Real Estate Group from 1996 to 1999. Mr. Jones is a Chartered Financial Analyst.

Nancy J. McGurk has been our Chief Accounting Officer since our formation in 2006 and Chief Accounting Officer of Atlas Energy Management since its formation. She has been the Chief Accounting Officer of Atlas America since January 2001 and Senior Vice President since January 2002. Ms. McGurk was a Vice President of Resource America from 1992 until May 2004, and its Treasurer and Chief Accounting Officer from 1989 until May 2004. Ms. McGurk has been Senior Vice President of Atlas Resources since January 2002 and Chief Financial Officer and Chief Accounting Officer since January 2001.

Lisa Washington has been our Chief Legal Officer and Secretary since August 2006 and Chief Legal Officer and Secretary of Atlas Energy Management since its formation. She has been the Chief Legal Officer and Secretary of Atlas Pipeline Holdings GP since January 2006. Ms. Washington has been the Vice President, Chief Legal Officer and Secretary of Atlas America and Atlas Pipeline Partners GP since November 2005. From 1999 to November 2005, Ms. Washington was an attorney in the business department of the law firm of Blank Rome LLP.

Walter C. Jones has been the General Counsel and Senior Director of Private Equity for GRAVITAS Capital Advisors, LLC, an independent investment advisory firm since May 2005. From May 1994 to May 2005, Mr. Jones was at the Overseas Private Investment Corporation, where he served as Manager for Asia, Africa, the Middle East, Latin America and the Caribbean, as well as for seven years a senior officer in the Finance Department.

Ellen F. Warren is founder and President of OutSource Communications, a marketing communications firm that services corporate and nonprofit clients. Prior to founding OutSource Communications in August 2005, she was President of Levy Warren Marketing Media, a public relations and marketing firm she co-founded in March 1998. Before that, she was Vice President of Marketing/Communications for Jefferson Bank, a Philadelphia-based financial institution from September 1992 to February 1998.

Bruce M. Wolf has been President of Homard Holdings, LLC, a wine manufacturer and distributor, since September 2003. Mr. Wolf has been of counsel with Picadio, Sneath, Miller & Norton, P.C., Pittsburgh, PA, since May 2003. Additionally, since June 1999, Mr. Wolf has been a consultant in connection with energy and securities matters, conducting research and providing expert testimony and litigation support. Mr. Wolf was a Senior Vice President of Atlas America from October 1998 to May 1999 and, before that, Secretary and General Counsel of Atlas Energy Group from 1980.

Mr. Weber will devote all of his professional time to our operations. Our other officers may spend a substantial amount of time managing the business and affairs of Atlas America and its affiliates. Our officers will devote as much time to our management as is necessary for the proper conduct of our

 


 

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business and affairs. The amount of time that our other executive officers will devote to our operations and to those of Atlas America, including Atlas Pipeline, depends on our and Atlas America’s needs but, in general, we estimate that Ms. McGurk will devote a majority of her time and Messrs. E. Cohen and Jones and Ms. Washington will devote approximately 45% of their time to our operations. Mr. J. Cohen serves as the chief executive officer of Resource America, Inc. and will not devote the majority of his time to Atlas America’s or our operations.

BOARD COMMITTEES

The board intends to appoint two functioning committees immediately following the pricing of this offering: an audit committee and a conflicts committee. We are not required under NYSE rules to have a nominating/corporate governance committee or compensation committee so long as we are a controlled company, which is defined as a company in which more than 50% of the voting power is held by an individual, a group or another company.

Audit Committee

We currently contemplate that the audit committee will consist of at least three directors. Immediately following the pricing of this offering, all members of the audit committee will be independent under the independence standards established by NYSE and SEC rules, and the committee expects to have an “audit committee financial expert,” as defined under SEC rules. The audit committee will recommend to the board the independent public accountants to audit our financial statements and establish the scope of, and oversee, the annual audit. The committee also will approve any other services provided by public accounting firms. The audit committee will provide assistance to the board in fulfilling its oversight responsibility to the unitholders, the investment community and others relating to the integrity of our financial statements, our compliance with legal and regulatory requirements, the independent auditor’s qualifications and independence and the performance of our internal audit function. The audit committee will oversee our system of disclosure controls and procedures and system of internal controls regarding financial, accounting, legal compliance and ethics that management and the board have established. In doing so, it will be the responsibility of the audit committee to maintain free and open communication between the committee and our independent auditors, the internal accounting function and management of our company. Upon the completion of this offering, Messrs. W. Jones and Wolf and Ms. Warren will comprise our audit committee.

Conflicts Committee

We currently contemplate that the conflicts committee will consist of at least three directors. The conflicts committee will review specific matters that the board believes may involve conflicts of interest. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to our company. Our limited liability company agreement will provide that members of the committee may not be officers or employees of our company, Atlas America or our manager or directors, officers or employees of any of our or their affiliates and must meet the independence standards for service on an audit committee of a board of directors as established by NYSE and SEC rules. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to our company and approved by all of our unitholders.

Our board of directors may, but is not required to, seek approval from the conflicts committee of a resolution of a conflict of interest with Atlas America or its affiliates. If our board of directors seeks approval from the conflicts committee, the conflicts committee will determine if the resolution of a conflict of interest is fair and reasonable to us. Any matters approved by the conflicts committee in good

 


 

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faith will be conclusively deemed to be fair and reasonable to us, approved by all of our unitholders and not a breach of obligation to us or our unitholders. If a matter is submitted to the conflicts committee and the conflicts committee does not approve the matter, we will not proceed with the matter unless and until the matter has been modified in such a manner that the conflicts committee determines is fair and reasonable to us. The resolution of conflicts may not always be in our best interest or that of our unitholders. For a more detailed description of the conflicts of interest involving us and the resolution of these conflicts, please read “Conflicts of interest and fiduciary duties—Conflicts of Interest.”

GOVERNANCE MATTERS

Independence of Board Members

Pursuant to the NYSE listing standards, a director will be considered independent if the board determines that he or she does not have a material relationship with us (either directly or as a member, unitholder or officer of an organization that has a material relationship with us). We are not required under the NYSE rules to have a majority of independent members of our board so long as we are a controlled company.

Heightened Independence for Audit Committee Members

As required by the Sarbanes-Oxley Act of 2002, the SEC has adopted rules that direct national securities exchanges and associations to prohibit the listing of securities of a public company if members of its audit committee do not satisfy a heightened independence standard. In order to meet this standard, a member of an audit committee may not receive any consulting fee, advisory fee or other compensation from the public company other than fees for service as a director or committee member and may not be considered an affiliate of the public company. Our board of directors expects that all members of its audit committee will satisfy this heightened independence requirement.

Audit Committee Financial Expert

An audit committee plays an important role in promoting effective corporate governance, and it is imperative that members of an audit committee have requisite financial literacy and expertise. As required by the Sarbanes-Oxley Act of 2002 and SEC rules promulgated thereunder, a public company must disclose whether its audit committee has a member that is an “audit committee financial expert.” An “audit committee financial expert” is defined as a person who, based on his or her experience, possesses all of the following attributes:

 

Ø   An understanding of generally accepted accounting principles and financial statements;

 

Ø   An ability to assess the general application of such principles in connection with the accounting for estimates, accruals and reserves;

 

Ø   Experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and level of complexity of issues that can reasonably be expected to be raised by a company’s financial statements, or experience actively supervising one or more persons engaged in such activities;

 

Ø   An understanding of internal controls and procedures for financial reporting; and

 

Ø   An understanding of audit committee functions.

Walter C. Jones will be our initial audit committee financial expert.

Executive Sessions of Board

Our board of directors will hold regular executive sessions in which non-management board members meet without any members of management present. The purpose of these executive sessions is to promote open and discussion among the non-management directors. During such executive sessions, one

 


 

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director is designated as the “presiding director” and is responsible for leading and facilitating such executive sessions.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

We do not have a compensation committee. There are no interlocks with other companies within the meaning of the SEC’s rules.

COMPENSATION OF DIRECTORS

We do not pay additional remuneration to our officers or to officers or employees of our manager who also serve as directors. Each non-employee director will receive an annual retainer of $35,000 in cash and an annual grant of phantom units with distribution equivalent rights in an amount equal to the lesser of 500 units or $15,000 worth of units, based upon the market price of our common units, pursuant to our long-term incentive plan. Please see “—Atlas Energy Resources Long-Term Incentive Plan” below. In addition, each independent board member is reimbursed for his or her out-of-pocket expenses in connection with attending meetings of the board or committees. We will indemnify our directors for actions associated with being board members to the extent permitted under Delaware law.

EXECUTIVE COMPENSATION

All of our current officers and directors have to date been employees of Atlas America, and they have received no additional compensation from us. Our manager will manage our operations and activities through its and its affiliates’ officers and employees pursuant to the management agreement under the direction of our board of directors. We will reimburse our manager for direct and indirect general and administrative expenses incurred on our behalf.

EMPLOYMENT AGREEMENT

We have no employment agreements for specific terms with our officers.

Atlas America and Richard D. Weber have entered into an employment agreement, dated April 5, 2006, pursuant to which Mr. Weber will serve as our President and Chief Operating Officer and the President and Chief Operating Officer of our manager. A brief description of the material terms and conditions of the agreement is as follows:

 

Ø   The term of the agreement is April 17, 2006 through April 17, 2008. After the first year of the agreement, the term will automatically renew daily so that on any day that the agreement is in effect, it will have a remaining term of at least one year.

 

Ø   Mr. Weber will receive an annual base salary of at least $300,000. During the first year of the agreement, Mr. Weber will also earn a bonus of at least $700,000.

 

Ø   Mr. Weber will also receive equity compensation as follows:

 

  Ø   At the time that we complete this offering, Mr. Weber will receive a grant of restricted common units with a value of $1,000,000. These units will vest 25% per year for four years; any unvested units will be forfeited in the event that Mr. Weber is no longer employed by us or our manager.

 

  Ø   Upon the completion of this offering, Mr. Weber will receive options to acquire 1% of the number of our common units then outstanding, less the number of restricted common units issued to Mr. Weber, with a strike price equal to the public offering price, vesting period of 25% per year for four years and a term of 10 years.

 


 

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  Ø   Upon execution of the agreement, Mr. Weber was granted options to purchase 50,000 shares of Atlas America stock at the fair market value of such stock, with a vesting period of 25% per year for four years and a term of 10 years.

All of the securities issued as set forth above will be registered with the Securities and Exchange Commission by the appropriate issuer, if they were not so registered at the time of issuance.

If any payments received by Mr. Weber as a result of a change of us, control of our manager or Atlas America are subject to excise tax, our manager will agree to make Mr. Weber whole for such tax and any income tax that would result from such payment.

Mr. Weber’s employment may be terminated without cause upon 45 days written notice, or for cause upon written notice setting forth the conduct constituting cause. Mr. Weber may terminate his employment for good reason or for any other reason upon 30 days’ written notice.

Key termination benefits under the agreement are as follows:

 

Ø   If Mr. Weber’s employment is terminated due to his death, our manager will pay Mr. Weber’s designated beneficiaries a cash payment consisting of the following amounts:

 

  Ø   any earned but unpaid portion of Mr. Weber’s base salary;

 

  Ø   an amount representing the bonus that Mr. Weber received from the prior fiscal year pro rated for the time employed during the current fiscal year;

 

  Ø   any accrued but unpaid bonus and vacation pay; and

 

  Ø   Mr. Weber’s spouse will have health insurance paid for one year.

 

Ø   If Mr. Weber’s employment is terminated for cause, our manager will pay to Mr. Weber his annual base salary and vacation pay accrued through the date of such termination.

 

Ø   If Mr. Weber’s employment is terminated by him other than for good cause, our manager will pay to Mr. Weber his annual base salary accrued through the date of termination.

 

Ø   If Mr. Weber’s employment is terminated other than for cause or death, or Mr. Weber terminates his employment for good reason, our manager will pay amounts equal to Mr. Weber’s annual base salary, bonus, equity compensation and compensation and benefits otherwise payable to Mr. Weber upon his death, as if Mr. Weber remained employed pursuant to the agreement.

The agreement includes standard restrictive covenants for a period of two years following termination, including non-compete and non-solicitation provisions.

OUR MANAGER

We will enter into a management agreement with our manager pursuant to which it will be responsible for managing our day-to-day operations, subject to the supervision and direction of our board of directors. See “Certain relationships and related transactions—Agreements Governing the Transactions—The management agreement.” Neither we nor our manager will directly employ any of the persons responsible for our operations. Rather, personnel of Atlas America currently involved in managing our assets will manage and operate our business. Officers of our manager may spend a substantial amount of time managing the business and affairs of Atlas America and its affiliates and may face a conflict regarding the allocation of their time between our business and affairs and their other business interests. Our manager intends to cause its officers to devote as much time to our management as is necessary for the proper conduct of our business and affairs.

 


 

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OFFICERS OF OUR MANAGER

The following table sets forth information with respect to the officers of our manager.

 

Name    Age    Position with manager

Edward E. Cohen

   67    Chairman of the Board and Chief Executive Officer

Richard D. Weber

   43    President, Chief Operating Officer and Director

Jeffrey C. Simmons

   48    Senior Vice President

Frank P. Carolas

   47    Senior Vice President

Matthew A. Jones

   45    Chief Financial Officer

Nancy J. McGurk

   50    Chief Accounting Officer

Donald R. Laughlin

   58    Vice President – Drilling and Production

Michael G. Hartzell

   51    Vice President – Land Administration

Lisa Washington

   39    Chief Legal Officer and Secretary

Please see “—Our Board of Directors and Executive Officers” for biographical information for Messrs. E. Cohen, R. Weber and M. Jones and Mss. McGurk and Washington.

Jeffrey C. Simmons has been a Senior Vice President since Atlas Energy Management’s formation. He has been an Executive Vice President of Atlas America since 2001 and was a director from January 2002 until February 2004. He has been Executive Vice President—Operations and a director of Atlas Resources, LLC, which acts as the general partner of some of our investment partnerships, since January 2001. Mr. Simmons was a Vice President of Resource America from April 2001 until May 2004. Mr. Simmons joined Resource America in 1986 as a senior petroleum engineer and served in various executive positions with its energy subsidiaries thereafter.

Frank P. Carolas has been a Senior Vice President since Atlas Energy Management’s formation. Mr. Carolas has been an Executive Vice President of Atlas America since January 2001 and served as a director from January 2002 until February 2004. Mr. Carolas was a Vice President of Resource America from April 2001 until May 2004, and has been Executive Vice President—Land and Geology and a director of Atlas Resources since January 2001. Mr. Carolas was Vice President of Atlas Resources from July 1999 to January 2001. Mr. Carolas is a certified petroleum geologist and has been employed by Atlas Resources and its affiliates since 1981.

Donald R. Laughlin has been Vice President—Drilling and Production of Atlas Energy Management since its formation. Mr. Laughlin has been Vice President—Drilling and Production of Atlas Resources since September 2001. Mr. Laughlin has also served as Vice President—Drilling and Production for Atlas America since January 2002, and before that served as Senior Drilling Engineer from May 2001, when he joined Atlas America. Mr. Laughlin has over thirty years of experience as a petroleum engineer in the Appalachian Basin, having been employed by Columbia Gas Transmission Corporation from October 1995 to May 2001 as a senior gas storage engineer and team leader, Cabot Oil & Gas Corporation from 1989 to 1995 as Manager of Drilling Operations and Technical Services, Doran & Associates, Inc.

Michael G. Hartzell has been Vice President—Land Administration for Atlas Energy Management since its formation. Mr. Hartzell has been Vice President—Land Administration of Atlas Resources since September 2001 and of Atlas America since January 2002. Before that Mr. Hartzell served as Senior Land Coordinator of Atlas Resources from January 1999 to January 2002. Mr. Hartzell has been with Atlas Resources and its affiliates since 1980, when he began his career as a land department representative. Mr. Hartzell serves on the Environmental Committee of the Independent Oil and Gas Association of Pennsylvania and is a past Chairman of the Committee.

 


 

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OTHER SIGNIFICANT EMPLOYEES

Freddie M. Kotek, 50, has been an Executive Vice President of Atlas America since February 2004 and served as Chief Financial Officer from February 2004 until March 2005 and a director from September 2001 until February 2004. Mr. Kotek was a Senior Vice President of Resource America from 1995 until May 2004, and has been Chairman of Atlas Resources since September 2001 and Chief Executive Officer and President of Atlas Resources since January 2002.

Jack L. Hollander, 50, has been Senior Vice President—Direct Participation Programs of Atlas Resource since January 2002 and before that he served as Vice President—Direct Participation Programs. Mr. Hollander also has served as Senior Vice President—Direct Participation Programs of Atlas America since January 2002. Mr. Hollander practiced law with Rattet, Hollander & Pasternak, concentrating in tax matters and real estate transactions, from 1990 to January 2001, and served as in-house counsel for Integrated Resources, Inc. (a diversified financial services company) from 1982 to 1990. Mr. Hollander is a member of the New York bar and the Chairman of the Investment Program Association, an industry association, as of March 2005.

Marci F. Bleichmar, 36, has been Vice President—Marketing of Atlas Resources since February 2001. Ms. Bleichmar has also served as Vice President of Marketing for Atlas America since February 2001 and was with Resource America from February 2001 until May 2004. From March 2000 until February 2001, Ms Bleichmar served as Director of Marketing for Jacob Asset Management (a mutual fund manager), and from March 1998 until March 2000, she was an account executive at Bloomberg Financial Services, L.P.

Daniel C. Herz, 29, has been Vice President of Corporate Development of Atlas America and Atlas Pipeline Partners GP since December 2004 and of Atlas Pipeline Holdings GP since January 2006. Mr. Herz joined Atlas America and Atlas Pipeline Partners GP in January 2004. He was an Associate Investment Banker with Banc of America Securities from 2002 to 2003 and an Analyst from 1999 to 2002.

COMPENSATION OF OUR MANAGER’S DIRECTORS

Our manager’s directors will not be paid annual retainer fees or other separate compensation for serving on the manager’s board of directors or attending board meetings.

REIMBURSEMENT OF EXPENSES OF OUR MANAGER AND ITS AFFILIATES

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

 


 

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ATLAS ENERGY RESOURCES LONG-TERM INCENTIVE PLAN

Before the closing of this offering, we will adopt the Atlas Energy Resources Long-Term Incentive Plan for our officers and directors and the employees, directors and consultants of our manager and its affiliates, including Atlas America, who perform services for us. The long-term incentive plan will consist of common unit grants, restricted units, phantom units, unit options and tandem distribution equivalent rights with respect to phantom units. The long-term incentive plan will be administered by our board of directors or a committee delegated by the board, which may be the compensation committee of the board of directors of Atlas America. We refer to the body responsible for administering the plan as the administrator.

The administrator may terminate or amend the long-term incentive plan at any time with respect to any units for which a grant has not yet been made. It will also have the right to alter or amend the long-term incentive plan or any part of the long-term incentive plan from time to time, including increasing the number of common units that may be granted, subject to unitholder approval as may be required by the exchange upon which our common units are listed at that time, if any. Subject to adjustment as provided in the long-term incentive plan documents, the aggregate number of our common units that may be awarded to participants is 3,742,000. However, no change in any outstanding grant may be made that would materially reduce the benefits of the participant without the consent of the participant. Units with respect to awards forfeited, terminated or paid without the delivery of common units are available for delivery pursuant to other awards. The long-term incentive plan will expire upon its termination by the administrator or, if earlier, when no units remain available under the long-term incentive plan for awards. Upon termination of the long-term incentive plan, awards then outstanding will continue pursuant to the terms of their grants.

Common Unit Grants

A common unit grant is a grant of common units that vests immediately upon issuance.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture prior to the vesting of the award. A phantom unit entitles the grantee to receive a unit upon the vesting of the phantom unit or, in the discretion of the administrator, cash equivalent to the value of a unit. The administrator may make grants of restricted units or phantom units under the plan to eligible participants containing such terms as it determines. The administrator will determine the period over which restricted units or phantom units will vest. The administrator, in its discretion, may base its determination upon the achievement of specified financial objectives or other events. In addition, the restricted units or phantom units will vest upon a change in control. If a grantee’s employment, consulting or board membership relationship with our manager or its affiliates terminates for any reason, the grantee’s restricted units or phantom units will be automatically forfeited unless the administrator or the terms of the award agreement provide otherwise.

We intend that the issuance of any units upon vesting of the restricted units or phantom units under the plan serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of our common units. Therefore, plan participants will not pay any consideration for the units they receive, and we will receive no remuneration for the units.

DERs

A distribution equivalent right or DER is a right granted in the administrator’s discretion with respect to a phantom unit that entitles the grantee to receive cash equal to the cash distributed on a common unit on such terms and conditions as the administrator may proscribe.

Options

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option. The administrator will determine the eligible participants to whom options are granted, the number of options, their vesting provisions, exercise price and other terms and conditions.

Common units to be delivered upon the issuance of a common unit grant or the vesting of restricted units, phantom units or the exercise of options may be units acquired by us in the open market, units acquired by us from any other person or any combination of the foregoing. If we issue new common units upon the issuance of a common unit grant or the vesting of the restricted units, phantom units or the exercise of options, the total number of common units outstanding will increase.

 


 

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Certain relationships and related transactions

After this offering, assuming no exercise of the underwriters’ option to purchase additional common units:

 

Ø   Our manager will own 748,456 Class A units, representing a 2% limited liability company interest in us, and all of the management incentive interests; and

 

Ø   Atlas America will own 30,299,365 common units, representing an approximate 81% limited liability company interest in us.

DISTRIBUTIONS AND PAYMENTS TO OUR MANAGER AND ATLAS AMERICA

The following table summarizes the distributions and payments to be made by us to our manager and Atlas America in connection with our formation, ongoing operation and any liquidation. These distributions and payments were determined among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

 

Formation Stage

 

Consideration received by our manager and Atlas America in our restructuring

 

Ø 748,456 Class A units;

Ø 30,299,365 common units;

Ø the management incentive interests; and

Ø the net proceeds of this offering, after payment of offering expenses.

Operational Stage

 

Distributions of available cash to our manager and Atlas America

 

We will generally make cash distributions 98% to common unitholders, including Atlas America, and 2% to our manager with respect to its Class A units. In addition, if distributions exceed the First Target Distribution and certain other requirements are met, our manager will be entitled with respect to its management incentive interests to 15% of distributions above the First Target Distribution and 25% of distributions above the Second Target Distribution. For a discussion of the management incentive interests, please read “How we make cash distributions—Management Incentive Interests.” Assuming we have sufficient available cash to pay the IQD on all of our outstanding units for four quarters, but no distributions in excess of the full IQD, our manager would receive an annual distribution of approximately $1.3 million on its Class A units and Atlas America would receive an annual distribution of approximately $50.9 million on its common units. On a pro forma basis for the twelve months ended September 30, 2006, our manager would have received distributions of approximately $447,400 on the Class A units and Atlas America would have received distributions of

 


 

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  approximately $18.1 million on its common units. There is no cap on the distributions we may make with respect to the Class A units and management incentive interests.

Payments to our manager

  Pursuant to our management agreement with our manager, we will be obligated to reimburse our manager for the costs it incurs in providing services to us. There is no cap on the expense reimbursements we may make to our manager.

Conversion of Class A units and management incentive interests

 

If we terminate the management agreement, our manager will have the option to convert:

 

Ø its Class A units into common units on a one for one basis; and

Ø its management incentive interests into common units based on their then fair market value, unless the successor manager purchases them.

 

If the common unitholders vote to eliminate the special voting rights of the Class A units, the Class A units will automatically convert to common units and our manager will have the option to convert the management incentive interests into common units based on their then fair market value.

Liquidation Stage

 

Liquidation

  Upon our liquidation, the unitholders, including Atlas America as a common unitholder, and our manager, as the holder of the Class A units, will be entitled to receive liquidating distributions according to their respective capital account balances. Please read “How we make cash distributions—Distributions of Cash Upon Liquidation.”

AGREEMENTS GOVERNING THE TRANSACTIONS

We and our manager and its affiliates will enter into the various agreements that will effect the offering transactions, including the contribution by Atlas America of its natural gas and oil development and production subsidiaries to us. These agreements will not be the result of arm’s-length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms at least as favorable to the parties to these agreements as they could have been obtained from unaffiliated third parties. All of the transaction expenses incurred in connection with these transactions will be paid from the proceeds of this offering.

The contribution agreement

Contribution of assets by Atlas America.    Before the closing of this offering, the substantial majority of the assets we will own are held, directly or indirectly, by subsidiaries of Atlas America. In connection with this offering, Atlas America will enter into a contribution agreement pursuant to which, at closing, it will contribute to us all of the stock of its natural gas and oil development and production subsidiaries as well as the development and production assets owned by it.

 


 

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As consideration for this contribution, we will distribute to Atlas America the net proceeds we receive from this offering, as well as 30,299,365 of our common units, assuming no exercise of the underwriters’ option to purchase additional common units, the Class A units and the management incentive interests. As part of the contribution agreement, Atlas America will indemnify us for one year after the closing of this offering against certain potential environmental liabilities associated with the operation of the assets and occurring before the closing date of this offering and against claims for covered environmental liabilities made before the fourth anniversary of the closing of this offering. The obligation of the indemnitors will not exceed $25.0 million, and they will not have any indemnification obligation until our losses exceed $500,000 in the aggregate, and then only to the extent such aggregate losses exceed $500,000. Additionally, Atlas America will indemnify us for losses attributable to title defects to our oil and gas property interests for three years after the closing of this offering, and indefinitely for losses attributable to retained liabilities and income taxes attributable to pre-closing operations and the formation transactions. Furthermore, we will indemnify Atlas America for all losses attributable to the post-closing operations of the assets contributed to us, to the extent not subject to its indemnification obligations.

Atlas America’s Assumption of Obligations under the Master Natural Gas Gathering Agreement with Atlas Pipeline.    Upon completion of this offering, we will become a party to an existing master natural gas gathering agreement between Atlas America and Atlas Pipeline pursuant to which Atlas Pipeline will gather substantially all of the natural gas from wells operated by us. We will be separately obligated to connect wells owned by us or our investment partnerships to Atlas Pipeline’s systems pursuant to an omnibus agreement with Atlas Pipeline to which we will also become a party. Please see “Business—Natural Gas Gathering.” The gathering fees payable to Atlas Pipeline under the gathering agreement generally exceed the amount we receive from our investment partnerships for gathering. Pursuant to the contribution agreement, Atlas America will agree to assume our obligation to pay these gathering fees to Atlas Pipeline; we will agree to pay Atlas America the gathering fees we receive from our investment partnerships and fees associated with production to our interest. See “Risk factors—Risks Inherent in Our Business—If Atlas America fails to pay gathering fees to Atlas Pipeline as required by its assumption agreement with us, we would have to pay to Atlas Pipeline the difference between the gathering fee payable and the amount we receive from our investment partnerships for gathering services out of our own resources.”

The management agreement

Duties.    Before completion of the offering, we will enter into a management agreement with our manager that will require it to manage our business affairs under the supervision of our board of directors. Our manager will provide us with all services necessary or appropriate for us to conduct our business, including the following:

 

Ø   providing executive and administrative personnel, office space and office services required in rendering services to us;

 

Ø   investigating, analyzing and proposing possible acquisition and investment opportunities;

 

Ø   evaluating and recommending to our board of directors and officers hedging strategies and engaging in hedging activities on our behalf, consistent with such strategies;

 

Ø   negotiating agreements on our behalf;

 

Ø   communicating on our behalf with the holders of any of our equity or debt securities as required to satisfy the reporting and other requirements of any governmental bodies or agencies or trading markets and to maintain effective relations with such holders;

 

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Ø   furnishing reports and statistical and economic research to us regarding our activities and services performed for us by our manager;

 

Ø   monitoring our operating performance and providing periodic reports with respect thereto to our board of directors, including comparative information with respect to such operating performance and budgeted or projected operating results;

 

Ø   at the direction of the audit committee of our board of directors, causing us to retain qualified accountants to assist in developing appropriate accounting procedures, compliance procedures and testing systems with respect to financial reporting obligations, and to conduct quarterly compliance reviews with respect thereto;

 

Ø   causing us to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses;

 

Ø   assisting us in complying with all regulatory requirements applicable to us with respect to our business activities, including preparing or causing to be prepared all financial statements required under applicable regulations and contractual undertakings, all required tax filings and all reports and documents, if any, required under the Exchange Act;

 

Ø   handling and resolving all claims, disputes or controversies (including all litigation, arbitration, settlement or other proceedings or negotiations) in which we may be involved or to which we may be subject arising out of our day-to-day operations, subject to such limitations or parameters as may be imposed from time to time by our board of directors;

 

Ø   using commercially reasonable efforts to cause expenses incurred by or on behalf of us to be commercially reasonable or commercially customary and within any budgeted parameters or expense guidelines set by our board of directors from time to time;

 

Ø   advising us with respect to obtaining financing for our operations;

 

Ø   performing such other services as may be required from time to time for management and other activities relating to our assets as our board of directors shall reasonably request or our manager shall deem appropriate under the particular circumstances;

 

Ø   obtaining and maintaining, on our behalf, insurance coverage for our business and operations, including errors and omissions insurance with respect to the services provided by the manager, in each case in the types and minimum limits as the manager determines to be appropriate and as is consistent with standard industry practice; and

 

Ø   using commercially reasonable efforts to cause us to comply with all applicable laws.

Termination

The management agreement does not have a specific term, however, our manager may not terminate the agreement before its tenth anniversary. We may terminate the management agreement only upon the affirmative vote of holders of at least two-thirds of our outstanding common units, including units held by Atlas America and its affiliates.

In the event we terminate the management agreement, the manager will have the option to require the successor manager, if any, to purchase the Class A units and management incentive interests for their fair market value as determined by agreement between the departing manager and the successor manager. If no agreement is reached, an independent expert selected by the departing manager and the successor manager will determine the fair market value. If the departing manager and the successor manager cannot agree on an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value. If the purchase option is not exercised by either the departing

 


 

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manager or the successor manager, the Class A units will be converted into common units on a one for one basis and the management incentive interests will convert into common units equal to the fair market value of those interests as determined by an independent expert selected by agreement between the manager and the conflicts committee.

Reimbursement of expenses

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

Standard of care

In exercising its powers and discharging its duties under the management agreement, our manager will be required to act in good faith.

Limited liability; Indemnification

Pursuant to the management agreement, our manager will not assume any responsibility beyond the duties specified in the management agreement and will not be responsible for any action of our board of directors in following or declining to follow its advice or recommendations. Our manager, its stockholders, directors, officers, employees and affiliates will not be liable to us, any subsidiary of ours, our directors or our 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. We will agree to indemnify our manager, its stockholders, directors, officers, employees and affiliates with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of our manager, 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. Our manager and its affiliates will agree to indemnify us, our directors and officers with respect to all expenses, losses, damages, liabilities, demands, charges and claims arising from acts of our manager or its affiliates constituting gross negligence, bad faith, willful misconduct, fraud or a knowing violation of criminal law or any claims by employees of our manager or its affiliates relating to the terms and conditions of their employment. Our manager and/or Atlas America will carry errors and omissions and other customary insurance upon the completion of the offering.

Amendments

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

The omnibus agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Atlas America that will govern our relationship with it and its affiliates with respect to certain matters not governed by the

 


 

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management agreement. The omnibus agreement will remain in effect so long as Atlas America or one of its affiliates has the power, directly or indirectly, to direct our management and policies. We will also become party to an existing omnibus agreement between Atlas America and Atlas Pipeline as described in “Business—Natural Gas Gathering.”

Business opportunities

Pursuant to the omnibus agreement, if a business opportunity with respect to an investment in or acquisition of a domestic natural gas or oil production or development business is presented to us or Atlas America or its affiliates, we will have the first right to pursue the business opportunity as follows:

 

Ø   If the opportunity is a control investment, that is, majority control of the voting securities of an entity, we will have the first right of refusal.

 

Ø   If the opportunity is a non-control investment, that is, less than majority control of the voting securities of an entity, Atlas America and its affiliates will not be restricted in their ability to pursue the opportunity and will not have an obligation to present the opportunity to us.

 

Ø   Notwithstanding the foregoing, if the opportunity involves an investment in natural gas or oil wells or other natural gas or oil rights, even a non-control investment, we will have the right of first refusal.

Anthem Securities, Inc. services agreement

One of the subsidiaries we will acquire from Atlas America at the closing of this offering is Anthem Securities, Inc., a registered broker-dealer and a member of the National Association of Securities Dealers, Inc., or NASD, which acts as the dealer-manager on our investment partnership offerings. Under a services agreement between Anthem Securities and Atlas America, Anthem Securities will, upon request, provide dealer-manager services to Atlas America, on substantially the same terms as Anthem Securities’ current dealer-manager agreements.

Registration rights

Under our limited liability company agreement, we will agree to register for sale under the Securities Act and applicable state securities laws (subject to certain limitations) any of our securities proposed to be sold by Atlas America, our manager or any of their affiliates if an exemption from the registration requirements is not available. These registration rights require us to file up to three registration statements. We have also agreed to include any securities held by Atlas America, our manager or any of their affiliates in any registration statement that we file to offer securities for cash, except an offering relating solely to an employee benefit plan and other similar exceptions. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units eligible for future sale.”

 


 

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Conflicts of interest and fiduciary duties

CONFLICTS OF INTEREST

General

Upon the closing of this offering, Atlas America and our manager, its wholly-owned subsidiary, will own 30,299,365 common units and all of our Class A units and management incentive interests. In addition, we will enter into a management agreement with our manager, and following this offering we will be dependent on our manager for the management of our operations. Please read “Certain relationships and related party transactions—Agreements Governing the Transactions—The Management Agreement.” Conflicts of interest exist and may arise in the future as a result of the relationships between members of our board of directors and Atlas America and its affiliates, including our manager, on the one hand, and us and our unitholders, on the other hand. These potential conflicts may relate to the divergent interests of these parties.

Pursuant to the omnibus agreement to be entered into in connection with the closing of this offering, we will agree to certain business opportunity arrangements to address potential conflicts that may arise between us and Atlas America as described in “Certain relationships and related transactions—Agreements Governing the Transactions—The Omnibus Agreement.”

Our board of directors or its conflicts committee will resolve, on behalf our unitholders, any conflicts between us and Atlas America and its affiliates. Our limited liability company agreement contains provisions that allow our board of directors to take into account the interests of parties in addition to our interests when resolving conflicts of interest. In effect, these provisions limit our board of directors’ fiduciary duties to the unitholders. Our limited liability company agreement also restricts the remedies available to unitholders for actions taken that, without those limitations, might constitute breaches of fiduciary duty. Whenever a conflict arises between Atlas America, our manager or their affiliates, on the one hand, and us or any other unitholder, on the other, our board of directors will resolve that conflict. All personnel performing services to us or our manager are required to report a conflict of interest, initially to their immediate supervisor who will then report to our chief legal officer. The chief legal officer will review the matter with senior management and, if appropriate, the board of directors.

A conflicts committee of our board of directors will, at the request of our board of directors, review conflicts of interest. The conflicts committee will consist of the independent directors, initially Ms. Warren and Messrs. W. Jones and Wolf. No breach of obligation will occur under our limited liability company agreement with respect to any conflict of interest if the resolution is:

 

Ø   approved by the conflicts committee of our board of directors;

 

Ø   approved by the vote of a majority of the outstanding units, excluding any common or Class A units owned by Atlas America, our manager or any of their affiliates, although our board of directors is not obligated to seek such approval;

 

Ø   on terms no less favorable to us than those generally provided to or available from unrelated third parties; or

 

Ø   fair to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our board of directors may adopt a resolution with respect to a conflict of interest provided that interested directors have recused themselves from participation. Our board of directors may, but is not required to seek the approval of such resolution from the conflicts committee. If our board of directors

 


 

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does not seek approval from the conflicts committee and our 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 the third and fourth bullet points 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 member of the company, the person bringing the proceeding will have the burden of overcoming the presumption. In addition, if our board of directors seeks approval from the conflicts committee, it will be presumed that, in making its decision, the conflicts committee acted in good faith. Unless the resolution of a conflict is specifically provided for in our limited liability company agreement, our board of directors or its conflicts committee may consider any factors in good faith when resolving a conflict. When our limited liability company agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in our best interests, unless the context otherwise requires.

In resolving a conflict, our board of directors or the conflicts committee will consider any factors it determines in good faith to be appropriate, including:

 

Ø   the relative interest of the parties involved in the conflict or affected by the action;

 

Ø   any customary or accepted industry practices or historical dealings with a particular person or entity; and

 

Ø   generally accepted accounting practices or principles and other factors as it considers relevant, if applicable.

If the conflicts committee determines that a conflict of interest is reasonably likely to adversely affect our unitholders, it will either not approve the resolution or seek unitholder approval of the resolution. The committee will have the authority to obtain advice and assistance from internal or external legal, financial and other advisors.

Conflicts of interest could arise in the situations described below, among others:

Actions taken by our board of directors will affect the amount of cash available for distribution to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of our board of directors regarding various matters, including:

 

Ø   amount and timing of asset purchases and sales;

 

Ø   cash expenditures;

 

Ø   amount of estimated maintenance capital expenditures, which affects the amount of operating surplus;

 

Ø   borrowings;

 

Ø   issuances of additional units; and

 

Ø   the creation, reduction or increase of reserves in any quarter.

In addition, our borrowings do not constitute a breach of any duty owed by our board of directors to the unitholders, including borrowings that have the purpose or effect of enabling our manager to receive management incentive distributions.

Atlas America and its affiliates may compete with us.

Except as provided in our omnibus agreement with Atlas America described in “Certain relationships and related transactions—Agreements Governing the Transactions—The omnibus agreement,” none of Atlas America or any of its affiliates is restricted from competing with us.

 


 

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Neither we nor our manager have any employees and rely on the employees of Atlas America and its affiliates.

Neither we nor our manager have any employees and rely solely on employees of Atlas America and its affiliates. Atlas America and its affiliates will conduct business and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition between us, Atlas America and their affiliates for the time and effort of the officers and employees who provide services to our manager. All of our officers are also officers of our manager. Our officers and the officers of our manager who provide services to us are not required to work full time on our affairs. These officers may devote significant time to the affairs of our manager’s affiliates. There may be significant conflicts between us and affiliates of our manager regarding the availability of these officers to manage us.

We must reimburse our manager and its affiliates for expenses.

We must reimburse our manager and its affiliates for costs incurred in managing and operating us, including costs incurred in rendering corporate staff and support services properly allocable to us. See “Management—Reimbursement of Expenses of Our Manager and its Affiliates.”

Contracts between us, on the one hand, and our manager and Atlas America and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Our limited liability company agreement, the management agreement, the contribution agreement, the omnibus agreement and any of the other agreements, contracts and arrangements between us on the one hand, and Atlas America, our manager and their affiliates on the other, are not or will not be the result of arm’s length negotiations.

FIDUCIARY DUTIES

Our limited liability company agreement provides that our business and affairs shall be managed under the direction of our board of directors. Our limited liability company agreement further provides that the authority and function of our board of directors and officers shall be identical to the authority and functions of a board of directors and officers of a corporation organized under the Delaware General Corporation Law, or DGCL. However, our directors and officers do not owe us the same duties that the directors and officers of a corporation organized under the DGCL would owe to their corporation. Rather, our limited liability company agreement provides that the fiduciary duties and obligations owed to us and our members by our board of directors and officers is generally to act in good faith in the performance of their duties on behalf. If our conflicts committee approves a transaction involving potential conflicts, or if a transaction is on terms generally available from unaffiliated third parties or an action is taken that is fair and reasonable to the company, unitholders will not be able to assert that such approval constituted a breach of fiduciary duties owed to them by our directors and officers.

We are unlike publicly-traded partnerships whose business and affairs are managed by a general partner with fiduciary duties to the partnership. While our manager will manage our day-to-day operations pursuant to the management agreement, subject to the oversight of our board of directors, we have no general partner with fiduciary duties to us. Our manager’s duties to us are contractual in nature and arise solely under the management agreement. As a consequence, our manager will not owe a fiduciary duty to us similar to that owed by a general partner to its limited partners or a board of directors to a corporation. Please read “Certain Relationships and Related Transactions—Management Agreement.”

 


 

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Security ownership of principal beneficial owners and management

The following table sets forth the beneficial ownership of our units immediately following the consummation of this offering and the formation transactions, assuming no exercise of the underwriters’ option to purchase additional common units, and held by:

 

Ø   each unitholder who then will be a beneficial owner of more than 5% of our outstanding units;

 

Ø   each of our officers and directors and named executive officers of our manager; and

 

Ø   our directors and executive officers of our manager as a group.

The amounts and percentage of units beneficially owned are reported on the basis of the SEC rules governing the determination of beneficial ownership of securities. Under the SEC rules, a person is deemed to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, and/or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest. Except as indicated by footnote, to our knowledge the persons named in the table below have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

The address for all entities and persons named below is 311 Rouser Road, Moon Township, PA 15108.

 

     Common units to be
beneficially owned
    Class A units to be
beneficially owned
   

Percentage
of total
units to be
beneficially
owned

 

 
Name    Number    Percentage     Number    Percentage    

Atlas America

   30,299,365    82.6 %   —      —       81.0 %

Atlas Energy Management

   —      —       748,456    100 %   2 %

Edward E. Cohen

   —      —       —      —       —    

Jonathan Z. Cohen

   —      —       —      —       —    

Richard D. Weber(1)

   50,000    *     —      —       *  

Matthew A. Jones

   —      —       —      —       —    

Nancy J. McGurk

   —      —       —      —       —    

Walter C. Jones

   —      —       —      —       —    

Ellen F. Warren

   —      —       —      —       —    

Bruce M. Wolf

   —      —       —      —       —    

All directors and executive officers as a group (8 persons)

   50,000    *     —      —       *  

*   Less than 1%.
(1)   Amount shown based on assumed offering price at the mid-point of the range shown on the front cover of this prospectus. These units are subject to forfeiture, vesting 25% on each anniversary of April 17, 2006, and therefore Mr. Weber has voting power but not investment power.

 


 

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Description of the common units

THE COMMON UNITS

The common units represent limited liability company interests in us. The holders of common units are entitled to participate in distributions and exercise the rights or privileges available to unitholders under our limited liability company agreement. For a description of the relative rights and preferences of holders of common units in and to distributions, please read this section and “How we make cash distributions.” For a description of the rights and privileges of unitholders under our limited liability company agreement, including voting rights, please read “Our limited liability company agreement.”

TRANSFER AGENT AND REGISTRAR

The American Stock Transfer and Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following fees that will be paid by unitholders:

 

Ø   surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

Ø   special charges for services requested by a holder of a common unit; and

 

Ø   other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may at any time resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and has accepted the appointment within 30 days after notice of the resignation or removal, we are authorized to act as the transfer agent and registrar until a successor is appointed.

TRANSFER OF COMMON UNITS

By transfer of common units in accordance with our limited liability company agreement, each transferee of common units will be admitted as a unitholder with respect to the units transferred when such transfer and admission is reflected on our books and records. Additionally, each transferee of common units:

 

Ø   becomes the record holder of the units;

 

Ø   automatically agrees to be bound by the terms and conditions of, and is deemed to have executed our limited liability company agreement;

 

Ø   represents that the transferee has the capacity, power and authority to enter into our limited liability company agreement;

 

Ø   grants powers of attorney to our officers and any liquidator of our company as specified in our limited liability company agreement; and

 

Ø   makes the consents and waivers contained in our limited liability company agreement.

 


 

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An assignee will become a unitholder of our company for the transferred common units upon the recording of the name of the assignee on our books and records.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 


 

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Our limited liability company agreement

The following is a summary of the material provisions of our limited liability company agreement. The form of our limited liability company agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of the form of this agreement upon request at no charge.

We summarize the following provisions of our limited liability company agreement elsewhere in this prospectus:

 

Ø   with regard to distributions of available cash, please read “How we make cash distributions;”

 

Ø   with regard to the transfer of common units, please read “Description of the units—Transfer of Common Units;” and

 

Ø   with regard to allocations of taxable income and taxable loss, please read “Material tax consequences.”

ORGANIZATION

Our company was formed in June 2006 and will remain in existence until dissolved in accordance with our limited liability company agreement.

PURPOSE

Under our limited liability company agreement, we are permitted to engage, directly or indirectly, in any activity that our board of directors approves and that a limited liability company organized under Delaware law lawfully may conduct; provided, that our board of directors shall not cause us to engage, directly or indirectly, in any business activities that it determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our board of directors has the ability to cause us and our operating subsidiaries to engage in activities other than the exploitation, development and production of natural gas reserves, our board of directors has no current plans to do so. Our board of directors is authorized in general to perform all acts it deems to be necessary or appropriate to carry out our purposes and to conduct our business.

FIDUCIARY DUTIES

For a description of fiduciary duties, please read “Conflicts of interest and fiduciary duties.”

AGREEMENT TO BE BOUND BY LIMITED LIABILITY COMPANY AGREEMENT; POWER OF ATTORNEY

By purchasing a common unit in us, you will be admitted as a member of our company and will be deemed to have agreed to be bound by the terms of our limited liability company agreement. Pursuant to this agreement, each unitholder and each person who acquires a common unit from a unitholder grants to our board of directors (and, if appointed, a liquidator) a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our board of directors the authority to make certain amendments to, and to make consents and waivers under and in accordance with, our limited liability company agreement.

 


 

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CAPITAL CONTRIBUTIONS

Unitholders (including holders of common units) are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

LIMITED LIABILITY

The Delaware Limited Liability Company Act, which we refer to as the Delaware Act, provides that any unitholder who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the company for the amount of the distribution for three years. Under the Delaware Act, a limited liability company may not make a distribution to any unitholder if, after the distribution, all liabilities of the company, other than liabilities to unitholders on account of their limited liability company interests and liabilities for which the recourse of creditors is limited to specific property of the company, would exceed the fair value of the assets of the company. For the purpose of determining the fair value of the assets of a company, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the company only to the extent that the fair value of that property exceeds the nonrecourse liability. Under the Delaware Act, an assignee who becomes a substituted unitholder of a company is liable for the obligations of his assignor to make contributions to the company, except the assignee is not obligated for liabilities unknown to him at the time he became a unitholder and that could not be ascertained from the limited liability company agreement.

Our subsidiaries will initially conduct business only in Kentucky, New York, Ohio, Oklahoma, Pennsylvania, Tennessee and West Virginia. We may decide to conduct business in other states, and maintenance of limited liability for us, as a member of our operating subsidiaries, may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there. Limitations on the liability of unitholders for the obligations of a limited liability company have not been clearly established in many jurisdictions. We will operate in a manner that our board of directors considers reasonable and necessary or appropriate to preserve the limited liability of our unitholders.

VOTING RIGHTS

Holders of our common units and our Class A units have voting rights on most matters. Upon the completion of this offering, our manager will own all of our Class A units and Atlas America will own 30,299,365 of our common units. Our manager will also own all of our management incentive interests, which do not have voting rights. The following matters require a unitholder vote:

 

Election of members of the board of directors

Following our initial public offering, our board of directors will consist of seven members, as required by our limited liability company agreement. At the first annual meeting of our unitholders following this offering, Class A and common unitholders, voting as a single class, will elect the board members. Please read “—Election of Members of Our Board of Directors.”

 

Issuance of additional securities including common units

No approval right.

 


 

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Amendment of our limited liability company agreement

Certain amendments may be made by our board of directors without unitholder approval. Other amendments generally require the approval of our common units and Class A units, voting as a single class. Please read “—Amendments of Our Limited Liability Company Agreement.”

 

Merger of our company or the sale of all or substantially all of our assets

Common unit majority and Class A unit majority. Please read “—Merger, Sale or Other Disposition of Assets.”

 

Dissolution of our company

Common unit majority and Class A unit majority. Please read “—Termination or Dissolution.”

Matters requiring the approval of a common unit majority require the approval of a majority of the outstanding common units voting together as a single class and matters requiring the approval of a Class A unit majority require the approval of a majority of the outstanding Class A units voting together as a single class.

ELIMINATION OF SPECIAL VOTING RIGHTS OF CLASS A UNITS

The class voting right of the Class A units can be eliminated only upon a proposal submitted by or with the consent of our board of directors and the vote of the holders of at least 66 2/3% of our outstanding common units. If such elimination is so approved, the Class A units will automatically convert into common units on a one-for-one basis and our manager will have the right to convert its management incentive interests into common units based on their then fair market value.

ISSUANCE OF ADDITIONAL SECURITIES

Our limited liability company agreement authorizes us to issue an unlimited number of additional securities and authorizes us to buy securities for the consideration and on the terms and conditions determined by our board of directors without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional units or other equity securities. Holders of any additional units we issue will be entitled to share equally with the then-existing holders of common units, Class A units and management incentive interests in our distributions of available cash. In addition, the issuance of additional units or other equity securities may dilute the value of the interests of the then-existing holders of units in our net assets.

In accordance with Delaware law and the provisions of our limited liability company agreement, we may also issue additional securities that, as determined by our board of directors, may have special voting or other rights to which the units are not entitled.

The holders of units will not have preemptive or preferential rights to acquire additional units or other securities.

 


 

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ELECTION OF MEMBERS OF OUR BOARD OF DIRECTORS

At our first annual meeting of members following this offering, all of the members of our board of directors will be elected by our Class A units and our common unitholders, voting together as a single class. The board of directors will be subject to a re-election on an annual basis at our annual meeting of members.

Removal of members of our board of directors

Any director may be removed, with or without cause, by the holders of a majority of the outstanding common units and Class A units then entitled to vote at an election of directors, voting as a single class.

Increase in the size of our board of directors

The size of our board of directors may increase only with the approval of a majority of the directors. If the size of our board of directors is so increased, the vacancy created thereby shall be filled by a person appointed by our board of directors until the next annual meeting of members.

AMENDMENT OF OUR LIMITED LIABILITY COMPANY AGREEMENT

General

Amendments to our limited liability company agreement may be proposed only by or with the consent of our board of directors. To adopt a proposed amendment, other than the amendments discussed below, our board of directors is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the unitholders to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a majority of the common units and the Class A units, voting together as a single class.

Prohibited amendments

No amendment may be made that would:

 

Ø   enlarge the obligations of any unitholder without its consent, unless approved by at least a majority of the type or class of member interests so affected; or

 

Ø   provide that we are not dissolved upon an election to dissolve our company by our board of directors that is approved by a common unit majority and a Class A unit majority.

The provision of our limited liability company agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 75% of the outstanding common units, voting together as a single class, and 75% of the outstanding Class A units, voting together as a single class.

No unitholder approval

Our board of directors may generally make amendments to our limited liability company agreement without the approval of any unitholder or assignee to reflect:

 

Ø   a change in our name, the location of our principal place of our business, our registered agent or our registered office;

 

Ø   the admission, substitution, withdrawal or removal of members in accordance with our limited liability company agreement;

 

Ø   the merger of our company or any of our subsidiaries into, or the conveyance of all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity;

 


 

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Ø   a change that our board of directors determines to be necessary or appropriate for us to qualify or continue our qualification as a company in which our members have limited liability under the laws of any state or to ensure that neither we, our operating subsidiaries nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

Ø   an amendment that is necessary, in the opinion of our counsel, to prevent us, our board of directors or our officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

Ø   an amendment that our board of directors determines to be necessary or appropriate for the authorization of additional securities or rights to acquire securities;

 

Ø   any amendment expressly permitted in our limited liability company agreement to be made by our board of directors acting alone;

 

Ø   an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our limited liability company agreement;

 

Ø   any amendment that our board of directors determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our limited liability company agreement;

 

Ø   a change in our fiscal year or taxable year and related changes;

 

Ø   a merger, conversion or conveyance effected in accordance with our limited liability company agreement; and

 

Ø   any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our board of directors may make amendments to our limited liability company agreement without the approval of any unitholder or assignee if our board of directors determines that those amendments:

 

Ø   do not adversely affect the unitholders (including any particular class of unitholders as compared to other classes of unitholders) in any material respect;

 

Ø   are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

Ø   are necessary or appropriate to facilitate the trading of units or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the units are or will be listed for trading, compliance with any of which our board of directors deems to be in the best interests of us and our unitholders;

 

Ø   are necessary or appropriate for any action taken by our board of directors relating to splits or combinations of units under the provisions of our limited liability company agreement; or

 

Ø   are required to effect the intent expressed in this prospectus or the intent of the provisions of our limited liability company agreement or are otherwise contemplated by our limited liability company agreement.

 


 

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Opinion of counsel and unitholder approval

Our board of directors will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to our unitholders or result in our being treated as an entity for federal income tax purposes if one of the amendments described above under “—No Unitholder Approval” should occur. No other amendments to our limited liability company agreement will become effective without the approval of holders of at least 90% of the outstanding common units and Class A units unless we obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any unitholder of our company.

Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of unitholders whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

MERGER, SALE OR OTHER DISPOSITION OF ASSETS

Our board of directors is generally prohibited, without the prior approval of the holders of a common unit majority and Class A unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries, provided that our board of directors may mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without that approval. Our board of directors may also sell all or substantially all of our assets under a foreclosure or other realization upon the encumbrances above without that approval.

If the conditions specified in our limited liability company agreement are satisfied, our board of directors may merge our company or any of its subsidiaries into, or convey all of our assets to, a newly-formed entity if the sole purpose of that merger or conveyance is to effect a mere change in our legal form into another limited liability entity. Our unitholders are not entitled to dissenters’ rights of appraisal under our limited liability company agreement or applicable Delaware law in the event of a merger or consolidation, a sale of all or substantially all of our assets or any other transaction or event.

TERMINATION AND DISSOLUTION

We will continue as a company until terminated under our limited liability company agreement. We will dissolve upon: (1) the election of our board of directors to dissolve us, if approved by the holders of a common unit majority and Class A unit majority; (2) the sale, exchange or other disposition of all or substantially all of the assets and properties of our company and our subsidiaries; or (3) the entry of a decree of judicial dissolution of our company.

LIQUIDATION AND DISTRIBUTION OF PROCEEDS

Upon our dissolution, the liquidator authorized to wind up our affairs will, acting with all of the powers of our board of directors that the liquidator deems necessary or desirable in its judgment, liquidate our assets and apply the proceeds of the liquidation as described in “How we make cash distributions—Distributions of Cash Upon Liquidation.”

 


 

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The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to unitholders in kind if it determines that a sale would be impractical or would cause undue loss to our unitholders.

ANTI-TAKEOVER PROVISIONS

Our limited liability company agreement contains specific provisions that are intended to discourage a person or group from attempting to take control of our company without the approval of our board of directors. Specifically, our limited liability company agreement provides that we will elect to have Section 203 of the DGCL apply to transactions in which an interested common unitholder (as described below) seeks to enter into a merger or business combination with us. Under this provision, such a holder will not be permitted to enter into a merger or business combination with us unless:

 

Ø   before such time, our board of directors approved either the business combination or the transaction that resulted in the common unitholder’s becoming an interested common unitholder;

 

Ø   upon consummation of the transaction that resulted in the common unitholder becoming an interested common unitholder, the interested common unitholder owned at least 85% of our outstanding common units at the time the transaction commenced, excluding for purposes of determining the number of common units outstanding those common units owned:

 

  Ø   by persons who are directors and also officers; and

 

  Ø   by employee common unit plans in which employee participants do not have the right to determine confidentially whether common units held subject to the plan will be tendered in a tender or exchange offer; or

 

Ø   at or after such time the business combination is approved by our board of directors and authorized at an annual or special meeting of our common unitholders, and not by written consent, by the affirmative vote of the holders of at least 66 2/3% of our outstanding voting common units that are not owned by the interested common unitholder.

Section 203 defines “business combination” to include:

 

Ø   any merger or consolidation involving the company and the interested common unitholder;

 

Ø   any sale, transfer, pledge or other disposition of 10% or more of the assets of the company involving the interested common unitholder;

 

Ø   subject to certain exceptions, any transaction that results in the issuance or transfer by the company of any common units of the company to the interested common unitholder;

 

Ø   any transaction involving the company that has the effect of increasing the proportionate share of the units of any class or series of the company beneficially owned by the interested common unitholder; or

 

Ø   the receipt by the interested common unitholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the company.

In general, an “interested common unitholder” is any person or entity, other than Atlas America, our manager, their affiliates or transferees, that beneficially owns (or within three years did own) 15% or more of the outstanding common units of the company and any entity or person affiliated with or controlling or controlled by such entity or person.

The existence of this provision would be expected to have an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging attempts that might result in a premium over the market price for common units held by common unitholders.

 


 

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Our limited liability agreement also restricts the voting rights of common unitholders by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than Atlas America, our manager, their affiliates or transferees and persons who acquire such units with the prior approval of our board of directors, cannot vote on any matter.

LIMITED CALL RIGHT

If at any time any person owns more than 87.5% of the then-issued and outstanding membership interests of any class, such person will have the right, which it may assign in whole or in part to any of its affiliates or to us, 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 our management, on at least 10 but not more than 60 days’ notice. The unitholders are not entitled to dissenters’ rights of appraisal under our limited liability company agreement or applicable Delaware law if this limited call right is exercised. The purchase price in the event of this purchase is the greater of:

 

Ø   the highest cash price paid by such person for any membership interests of the class purchased within the 90 days preceding the date on which such person first mails notice of its election to purchase those membership interests; or

 

Ø   the closing market price as of the date three days before the date the notice is mailed.

As a result of this limited call right, a holder of membership interests in our company may have his membership interests purchased at an undesirable time or price. Please read “Risk factors—Risks Related to Our Structure.” The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his units in the market. Please read “Material tax consequences—Disposition of Common Units.”

MEETINGS; VOTING

Except as described below regarding a person or group owning 20% or more of units then outstanding, unitholders on the record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited.

All notices of meetings of unitholders shall be sent or otherwise given in accordance with our limited liability company agreement not less than 10 days nor more than 60 days before the date of the meeting. The notice shall specify the place, date and hour of the meeting and (i) in the case of a special meeting, the general nature of the business to be transacted (no business other than that specified in the notice may be transacted) or (ii) in the case of the annual meeting, those matters which the board of directors, at the time of giving the notice, intends to present for action by the unitholders (but any proper matter may be presented at the meeting for such action). The notice of any meeting at which directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the board of directors intends to present for election. Any previously scheduled meeting of the unitholders may be postponed, and any special meeting of the unitholders may be cancelled, by resolution of the board of directors upon public notice given prior to the date previously scheduled for such meeting of unitholders.

Units that are owned by an assignee who is a record holder, but who has not yet been admitted as a member, shall be voted at the written direction of the record holder by a proxy designated by our board of directors. Absent direction of this kind, the units will not be voted, except that units held by us on behalf of non-citizen assignees shall be voted in the same ratios as the votes of unitholders on other units are cast.

 


 

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Any action required or permitted to be taken by our unitholders may be taken at a duly called annual or special meeting of unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take the action at a meeting. Special meetings of the unitholders may be called only by the chairman or vice chairman of our board of directors, our chief executive officer, president or board of directors.

Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional units having special voting rights could be issued. Please read “—Issuance of Additional Securities” above. However, if at any time any person or group, other than Atlas America, our manager and their affiliates, or a direct or subsequently approved transferee of Atlas America, our manager or their affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of units will be delivered to the record holder by us or by the transfer agent.

NON-CITIZEN ASSIGNEES; REDEMPTION

If we or any of our subsidiaries are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any unitholder or assignee, we may redeem, upon 30 days’ advance notice, the units held by the unitholder or assignee at their current market price. To avoid any cancellation or forfeiture, our board of directors may require each unitholder or assignee to furnish information about his nationality, citizenship or related status. If a unitholder or assignee fails to furnish information about his nationality, citizenship or other related status within 30 days after a request for the information or our board of directors determines after receipt of the information that the unitholder or assignee is not an eligible citizen, the unitholder or assignee may be treated as a non-citizen assignee. In addition to other limitations on the rights of an assignee who is not a substituted unitholder, a non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation.

INDEMNIFICATION

Under our limited liability company agreement and subject to specified limitations, we will indemnify to the fullest extent permitted by law from and against all losses, claims, damages or similar events any person who is or was our director or officer, or while serving as our director or officer, is or was serving as a tax matters member or, at our request, as a director, manager, officer, tax matters member, employee, partner, fiduciary or trustee of us or any of our subsidiaries. Additionally, we shall indemnify to the fullest extent permitted by law and authorized by our board of directors, from and against all losses, claims, damages or similar events any person is or was an employee or agent (other than an officer) of our company.

 


 

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Any indemnification under our limited liability company agreement will only be out of our assets. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our limited liability company agreement.

BOOKS AND REPORTS

We are required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of unitholders can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

RIGHT TO INSPECT OUR BOOKS AND RECORDS

Our limited liability company agreement provides that a unitholder can, for a purpose reasonably related to his interest as a unitholder, upon reasonable demand and at his own expense, have furnished to him:

 

Ø   a current list of the name and last known address of each unitholder;

 

Ø   a copy of our tax returns;

 

Ø   information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each unitholder and the date on which each became a unitholder;

 

Ø   copies of our limited liability company agreement, the certificate of formation of the company, related amendments and powers of attorney under which they have been executed;

 

Ø   information regarding the status of our business and financial condition; and

 

Ø   any other information regarding our affairs as is just and reasonable.

Our board of directors may, and intends to, keep confidential from our unitholders information that it believes to be in the nature of trade secrets or other information, the disclosure of which our board of directors believes in good faith is not in our best interests, information that could damage our company or our business, or information that we are required by law or by agreements with a third party to keep confidential.

 


 

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REGISTRATION RIGHTS

Under our limited liability company agreement, we have agreed to register for sale under the Securities Act and applicable state securities laws (subject to certain limitations) any common units proposed to be sold by Atlas America, our manager or any of their affiliates if an exemption from the registration requirements is not available. These registration rights require us to file up to three registration statements. We have also agreed to include any securities held by Atlas America, our manager or any of their affiliates in any registration statement that we file to offer securities for cash, except an offering relating solely to an employee benefit plan and other similar exceptions. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and commissions. Please read “Units eligible for future sale.”

 


 

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Units eligible for future sale

After the sale of the common units offered by this prospectus, Atlas America will own 30,299,365 common units and our manager will own all of our 748,456 Class A units and management incentive interests that may be converted into common units, at our manager’s election, if we terminate the management agreement or if the common unitholders vote to eliminate the special voting rights of the Class A units. The sale of these common units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in this offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of us cannot be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from those requirements under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

Ø   1% of the total number of the securities outstanding or

 

Ø   the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, notice requirements and the availability of current public information about us. A person who is not deemed to have been our affiliate at any time during the three months preceding a sale, and who has beneficially owned his or her common units for at least two years, can sell units under Rule 144 without regard to the public information requirements, volume limitations, manner of sale provisions or notice requirements of Rule 144.

The limited liability company agreement does not restrict our ability to issue additional equity securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, common units then outstanding. See “Our limited liability company agreement—Issuance of Additional Securities.”

Under the limited liability company agreement, Atlas America, our manager and their affiliates have the right to demand that we register under the Securities Act and state laws the offer and sale of any units that they hold. Subject to the terms and conditions of the limited liability company agreement, these registration rights allow Atlas America, our manager and their affiliates or their assignees to require registration of these units and to include these units in a registration by us of other units. These registration rights will continue in effect for two years following any withdrawal or removal of our manager as manager. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or prospectus. We will bear all costs and expenses of the registration.

Atlas America, our officers and directors and our manager, its officers and directors have agreed with the underwriters not to dispose of any units they beneficially own for a period of 180 days after the date of this prospectus, subject to certain exceptions. Please read “Underwriting.”

 


 

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Material tax consequences

This section is a discussion of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Ledgewood, P.C., counsel to us and our manager, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based on current provisions of the Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to us and our and our subsidiaries.

This section does not address all federal income tax matters that affect us or the unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), employee benefit plans, real estate investment trusts (REITs) or mutual funds. Accordingly, we urge each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of our common units.

No ruling has been or will be requested from the IRS regarding any matter that affects us or prospective unitholders. Instead, we will rely on opinions and advice of Ledgewood. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made in this discussion may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for our common units and the prices at which our common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and thus will be borne directly by our unitholders. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements regarding matters of law and legal conclusions set forth below, unless otherwise noted, are the opinion of Ledgewood and are based on the accuracy of the representations made by us. Statements of fact do not represent opinions of Ledgewood.

For the reasons described below, Ledgewood has not rendered an opinion with respect to the following specific federal income tax issues:

 

(1)   the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please read “—Tax Consequences of Unit Ownership— Treatment of Short Sales”);

 

(2)   whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”);

 

(3)   whether percentage depletion will be available to a unitholder or the extent of the percentage depletion deduction available to any unitholder (please read “—Tax Treatment of Operations—Depletion Deductions”); and

 


 

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(4)   whether the deduction related to United States production activities will be available to a unitholder or the extent of such deduction to any unitholder (please read “—Tax Treatment of Operations—Deduction for United States Production Activities”).

PARTNERSHIP STATUS

Except as discussed in the following paragraph, a limited liability company that has more than one member and that has not elected to be treated as a corporation is treated as a partnership for federal income tax purposes and, therefore, is not a taxable entity and incurs no federal income tax liability. Instead, each partner is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, even if no cash distributions are made to him. Distributions by a partnership to a partner are generally not taxable to the partner unless the amount of cash distributed to him is in excess of his adjusted basis in his partnership interest.

Section 7704 of the Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to in this discussion as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships 90% or more of the gross income of which for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the exploration, development, mining or production, processing, transportation and marketing of natural resources, including oil, natural gas, and products thereof. Other types of qualifying income include fee-based income derived from the drilling, management and operation of oil and natural gas wells for our investment partnerships, interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than 3% of our current income does not constitute qualifying income; however, this estimate could change from time to time. Based on and subject to this estimate, the factual representations made by us, and a review of the applicable legal authorities, Ledgewood is of the opinion that more than 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income can change from time to time.

No ruling has been or will be sought from the IRS, and the IRS has made no determination as to our status or the status of our operating subsidiaries for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code. Instead, we will rely on the opinion of Ledgewood. Ledgewood is of the opinion, based upon the Code, its regulations, published revenue rulings, court decisions and the representations described below, that we will be classified as a partnership, and each of our operating subsidiaries will be disregarded as an entity separate from us, for federal income tax purposes.

In rendering its opinion, Ledgewood has relied on factual representations made by us. The representations made by us upon which Ledgewood has relied include:

 

(a)   Neither we, nor any of our subsidiaries, have elected nor will we elect to be treated as a corporation; and

 

(b)   For each taxable year, more than 90% of our gross income will be income that Ledgewood has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Code.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the

 


 

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year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation would be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as taxable dividend income to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital to the extent of the unitholder’s tax basis in his units, or taxable capital gain, after the unitholder’s tax basis in his units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Ledgewood’s opinion that we will be classified as a partnership for federal income tax purposes.

UNITHOLDER STATUS

Unitholders who become our members will be treated as our partners for federal income tax purposes. Also, assignees who have executed and delivered transfer applications, and are awaiting admission as members, and unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their units will be treated as our partners for federal income tax purposes.

Because there is no direct or indirect controlling authority addressing the federal tax treatment of assignees of units who are entitled to execute and deliver transfer applications and thereby become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, the opinion of Ledgewood does not extend to these persons. Furthermore, a purchaser or other transferee of units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of units unless the units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those units.

A beneficial owner of units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Items of our income, gain, loss, or deduction are not reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These unitholders are urged to consult their own tax advisors with respect to the consequences of their status as partners in us for federal income tax purposes.

 


 

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TAX CONSEQUENCES OF UNIT OWNERSHIP

Flow-through of taxable income

We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year or years ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of distributions

Distributions made by us to a unitholder generally will not be taxable to him for federal income tax purposes to the extent of his tax basis in his units immediately before the distribution. Cash distributions made by us to a unitholder in an amount in excess of his tax basis in his units generally will be considered to be gain from the sale or exchange of those units, taxable in accordance with the rules described under “—Disposition of Common Units” below. To the extent that cash distributions made by us cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

Any reduction in a unitholder’s share of our liabilities for which no partner bears the economic risk of loss, known as “non-recourse liabilities,” will be treated as a distribution of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease his share of our nonrecourse liabilities and thus will result in a corresponding deemed distribution of cash, which may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including recapture of intangible drilling costs, depletion and depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in Section 751 of the Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having received his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Ratio of taxable income to distributions

We estimate that a purchaser of our common units in this offering who holds those units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2009, will be allocated an amount of federal taxable income for that period that will be less than 50% of the cash distributed to the unitholder with respect to that period. The ratio of taxable income allocable to cash distributions to the unitholders may increase after that. These estimates are based upon the assumption that gross income from operations will be sufficient to make estimated distributions on all common units and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we intend to adopt and with which the IRS could disagree. Accordingly, these estimates may not prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units.

 


 

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Basis of common units

A unitholder’s initial tax basis for his common units will be the amount he paid for the units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis generally will be decreased, but not below zero, by distributions to him from us, by his share of our losses, by depletion deductions taken by him to the extent such deductions do not exceed his proportionate share of the adjusted tax basis of the underlying producing properties, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder’s share of our nonrecourse liabilities will generally be based on his share of our profits. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on deductibility of losses

The deduction by a unitholder of his share of our losses will be limited to his tax basis in his common units and, in the case of an individual unitholder or a corporate unitholder, if more than 50% of the value of its stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations, to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that amount is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that his tax basis or at-risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of his tax basis in his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the common units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities. Moreover, a unitholder’s at risk amount will decrease by the amount of the unitholder’s depletion deductions and will increase to the extent of the amount by which the unitholder’s percentage depletion deductions with respect to our property exceed the unitholder’s share of the basis of that property.

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 would be limited to the at risk amount for that property and not 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 we own in computing a unitholder’s at risk limitation with respect to us. If a unitholder must compute his at risk amount separately with respect to each oil or gas property we own, he 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 common units as a whole.

 


 

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The passive loss limitation generally provides that individuals, estates, trusts and some closely held corporations and personal service 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. The passive loss limitation is applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will be available to offset only our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments, a unitholder’s investments in other publicly-traded partnerships, or a unitholder’s salary or active business income. If we dispose of all or only part of our interest in an oil or gas property, unitholders will be able to offset their suspended passive activity losses from our activities against the gain, if any, on the disposition. Any previously suspended losses in excess of the amount of gain recognized will remain suspended. Notwithstanding whether a natural gas and oil property is a separate activity, passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted by the unitholder in full only when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after certain other applicable limitations on deductions, including the at-risk rules and the tax basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitation on interest deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

Ø   interest on indebtedness properly allocable to property held for investment;

 

Ø   our interest expense attributable to portfolio income; and

 

Ø   the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a common unit.

Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment. The IRS has indicated that net passive income earned by a publicly-traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-level collections

If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a unitholder whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our limited liability company agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of common units and to adjust later distributions, so that after giving effect to these

 


 

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distributions, the priority and characterization of distributions otherwise applicable under our limited liability company agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

Allocation of income, gain, loss and deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the unitholders in accordance with their percentage interests in us. If we have a net loss for an entire year, the loss will be allocated to our unitholders according to their percentage interests in us to the extent of their positive capital account balances.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code to account for the difference between the tax basis and fair market value of our assets at the time of this offering, which assets are referred to in this discussion as “Contributed Property.” These allocations are required to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and the “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “book-tax disparity.” The effect of these allocations to a unitholder who purchases common units in this offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In the event we issue additional units or engage in certain other transactions in the future, Section 704(c) allocations will be made to all holders of partnership interests, including purchasers of common units in this offering, to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of the future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by other unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by Section 704(c), will generally be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a unitholder’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

Ø   his relative contributions to us;

 

Ø   the interests of all the unitholders in profits and losses;

 

Ø   the interest of all the unitholders in cash flow; and

 

Ø   the rights of all the unitholders to distributions of capital upon liquidation.

Ledgewood is of the opinion that, with the exception of the issues described in “—Tax Consequences of Unit Ownership—Section 754 Election,” “—Uniformity of Common units” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our limited liability company agreement will be given effect for federal income tax purposes in determining a unitholder’s share of an item of income, gain, loss or deduction.

 


 

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Treatment of short sales

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

 

Ø   none of our income, gain, loss or deduction with respect to those units would be reportable by the unitholder;

 

Ø   any cash distributions received by the unitholder with respect to those units would be fully taxable; and

 

Ø   all of these distributions would appear to be ordinary income.

Because there is no direct or indirect controlling authority on the issue, Ledgewood has not rendered an opinion regarding the treatment of a unitholder whose units are loaned to a short seller. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition are urged to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative minimum tax

Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 ($87,500 in the case of married individuals filing separately) of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult their tax advisors with respect to the impact of an investment in our units on their liability for the alternative minimum tax.

Tax rates

In general, the highest effective federal income tax rate for individuals currently is 35% and the maximum federal income tax rate for net capital gains of an individual currently is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 election

We will make the election permitted by Section 754 of the Code. That election is irrevocable without the consent of the IRS. That election will generally permit us to adjust a unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Code to reflect his purchase price. The Section 743(b) adjustment does not apply to a person who purchases units directly from us, and it belongs only to the purchaser and not to other unitholders. Please also read, however, “—Allocation of Income, Gain, Loss and Deduction” above. For purposes of this discussion, a unitholder’s inside basis in our assets has two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

Treasury Regulations under Section 743 of the Code require, if the remedial allocation method is adopted (which we will adopt), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain.

 


 

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A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depletion and depreciation deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built-in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built-in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, an intangible asset, is generally either nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

TAX TREATMENT OF OPERATIONS

Accounting method and taxable year

Our taxable year will end on December 31, 2006 because Atlas America, our majority owner, has a December year end.

Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. For example, a unitholder who uses the calendar year will be required to include in his income for 2006 his share of our income, gain, loss and deduction for our taxable year ending December 31, 2006. In addition, a unitholder who has a different taxable year than our taxable year and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than one year of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Depletion deductions

Subject to the limitations on deductibility of losses discussed above, unitholders will be entitled to deductions for the greater of either cost depletion or (if otherwise allowable) percentage depletion with respect to our natural gas and oil interests. Although the Code requires each unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the underlying property for depletion and other purposes, we intend to furnish each of our unitholders with information relating to this computation for federal income tax purposes.

 


 

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Percentage depletion is generally available with respect to unitholders who qualify under the independent producer exemption contained in Section 613A(c) of the Code. For this purpose, an independent producer is a person not directly or indirectly involved in the retail sale of oil, natural gas, or derivative products or the operation of a major refinery. Percentage depletion is calculated as an amount generally equal to 15% (and, in the case of marginal production, potentially a higher percentage) of the unitholder’s gross income from the depletable property for the taxable year. The percentage depletion deduction with respect to any property is limited to 100% of the taxable income of the unitholder from the property for each taxable year, computed without the depletion allowance. A unitholder that qualifies as an independent producer may deduct percentage depletion only to the extent the unitholder’s daily production of domestic crude oil, or the natural gas equivalent, does not exceed 1,000 barrels. This depletable amount may be allocated between natural gas and oil production, with 6,000 cubic feet of domestic natural gas production regarded as equivalent to one barrel of crude oil. The 1,000 barrel limitation must be allocated among the independent producer and controlled or related persons and family members in proportion to the respective production by such persons during the period in question.

In addition to the foregoing limitations, the percentage depletion deduction otherwise available is limited to 65% of a unitholder’s total taxable income from all sources for the year, computed without the depletion allowance, net operating loss carrybacks, or capital loss carrybacks. Any percentage depletion deduction disallowed because of the 65% limitation may be deducted in the following taxable year if the percentage depletion deduction for such year plus the deduction carryover does not exceed 65% of the unitholder’s total taxable income for that year. The carryover period resulting from the 65% net income limitation is indefinite.

Unitholders that do not qualify under the independent producer exemption are generally restricted to depletion deductions based on cost depletion. Cost depletion deductions are calculated by (i) dividing the unitholder’s share of the adjusted tax basis in the underlying mineral property by the number of mineral units (barrels of oil and Mcf of natural gas) remaining as of the beginning of the taxable year and (ii) multiplying the result by the number of mineral units sold within the taxable year. The total amount of deductions based on cost depletion cannot exceed the unitholder’s share of the total adjusted tax basis in the property.

All or a portion of any gain recognized by a unitholder as a result of either the disposition by us of some or all of our natural gas and oil interests or the disposition by the unitholder of some or all of his units may be taxed as ordinary income to the extent of recapture of depletion deductions, except for percentage depletion deductions in excess of the basis of the property. The amount of the recapture is generally limited to the amount of gain recognized on the disposition.

The foregoing discussion of depletion deductions does not purport to be a complete analysis of the complex legislation and Treasury Regulations relating to the availability and calculation of depletion deductions by the unitholders. Further, because depletion is required to be computed separately by each unitholder and not by our partnership, no assurance can be given, and counsel is unable to express any opinion, with respect to the availability or extent of percentage depletion deductions to the unitholders for any taxable year. We encourage each prospective unitholder to consult his tax advisor to determine whether percentage depletion would be available to him.

Deductions for intangible drilling and development costs

Under our existing investment partnership agreements, all intangible drilling and development costs, which we refer to as IDCs, are allocated to investors in the partnerships and none to us. IDCs generally

 


 

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include our expenses for wages, fuel, repairs, hauling, supplies and other items that are incidental to, and necessary for, the drilling and preparation of wells for the production of oil, natural gas, or geothermal energy. The option to currently deduct IDCs applies only to those items that do not have a salvage value.

In future investment partnerships, a portion of IDCs may be allocated to us. In addition, we may undertake drilling for our own account. Should we be entitled to IDCs, we will elect to currently deduct them.

Although we will elect to currently deduct IDCs that may be available to us, each unitholder will have the option of either currently deducting IDCs or capitalizing all or part of the IDCs and amortizing them on a straight-line basis over a 60-month period, beginning with the taxable month in which the expenditure is made. If a unitholder makes the election to amortize the IDCs over a 60-month period, no IDC preference amount will result for alternative minimum tax purposes.

Integrated oil companies must capitalize 30% of all their IDCs (other than IDCs paid or incurred with respect to natural gas and oil wells located outside of the United States) and amortize these IDCs over 60 months beginning in the month in which those costs are paid or incurred. If the taxpayer ceases to be an integrated oil company, it must continue to amortize those costs as long as it continues to own the property to which the IDCs relate. An “integrated oil company” is a taxpayer that has economic interests in crude oil deposits and also carries on substantial retailing or refining operations. An oil or gas producer is deemed to be a substantial retailer or refiner if it is subject to the rules disqualifying retailers and refiners from taking percentage depletion. In order to qualify as an “independent producer” that is not subject to these IDC deduction limits, a unitholder, either directly or indirectly through certain related parties, may not be involved in the refining of more than 75,000 barrels of oil (or the equivalent amount of natural gas) on average for any day during the taxable year or in the retail marketing of natural gas and oil products exceeding $5 million per year in the aggregate.

IDCs previously deducted that are allocable to property (directly or through ownership of an interest in a partnership) and that would have been included in the adjusted basis of the property had the IDC deduction not been taken are recaptured to the extent of any gain realized upon the disposition of the property or upon the disposition by a unitholder of interests in us. Recapture is generally determined at the unitholder level. Where only a portion of the recapture property is sold, any IDCs related to the entire property are recaptured to the extent of the gain realized on the portion of the property sold. In the case of a disposition of an undivided interest in a property, a proportionate amount of the IDCs with respect to the property is treated as allocable to the transferred undivided interest to the extent of any gain recognized. See “—Disposition of Common Units—Recognition of Gain or Loss.”

Deduction for United States production activities

Subject to the limitations on the deductibility of losses discussed above and the limitation discussed below, unitholders will be entitled to a deduction, herein referred to as the Section 199 deduction, equal to a specified percentage of our qualified production activities income that is allocated to such unitholder. The percentages are 3% for qualified production activities income generated in the year 2006; 6% for the years 2007, 2008, and 2009; and 9% thereafter.

Qualified production activities income is generally equal to gross receipts from domestic production activities reduced by cost of goods sold allocable to those receipts, other expenses directly associated with those receipts, and a share of other deductions, expenses and losses that are not directly allocable to those receipts or another class of income. The products produced must be manufactured, produced, expanded or extracted in whole or in significant part by the taxpayer in the United States.

 


 

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For a partnership, the Section 199 deduction is determined at the partner level. To determine his Section 199 deduction, each unitholder will aggregate his share of the qualified production activities income allocated to him from us with the unitholder’s qualified production activities income from other sources. Each unitholder must take into account his distributive share of the expenses allocated to him from our qualified production activities regardless of whether we otherwise have taxable income. However, our expenses that otherwise would be taken into account for purposes of computing the Section 199 deduction are only taken into account if and to the extent the unitholder’s share of losses and deductions from all of our activities is not disallowed by the basis rules, the at-risk rules or the passive activity loss rules. Please read “—Tax Consequences of Unit Ownership—Limitations on Deductibility of Losses.”

The amount of a unitholder’s Section 199 deduction for each year is limited to 50% of the IRS Form W-2 wages paid by the unitholder during the calendar year that are deducted in arriving at qualified production activities income. Each unitholder is treated as having been allocated IRS Form W-2 wages from us equal to the unitholder’s allocable share of our wages that are deducted in arriving at our qualified production activities income for that taxable year. It is not anticipated that we or our subsidiaries will pay material wages that will be allocated to our unitholders.

This discussion of the Section 199 deduction does not purport to be a complete analysis of the complex legislation and Treasury authority relating to the calculation of domestic production gross receipts, qualified production activities income, or IRS Form W-2 Wages, or how such items are allocated by us to unitholders. Further, because the Section 199 deduction is required to be computed separately by each unitholder, no assurance can be given, and counsel is unable to express any opinion, as to the availability or extent of the Section 199 deduction to the unitholders. Each prospective unitholder is encouraged to consult his tax advisor to determine whether the Section 199 deduction would be available to him.

Lease Acquisition Costs

The cost of acquiring natural gas and oil leaseholder or similar property interests is a capital expenditure that must be recovered through depletion deductions if the lease is productive. If a lease is proved worthless and abandoned, the cost of acquisition less any depletion claimed may be deducted as an ordinary loss in the year the lease becomes worthless. Please read “Tax Treatment of Operations—Depletion Deductions.”

Geophysical Costs

The costs of geophysical exploration incurred in connection with the exploration and development of oil and gas properties in the United States are deduced ratably over a 24-month period beginning on the date that such expense is paid or incurred.

Operating and Administrative Costs

Amounts paid for operating a producing well are deductible as ordinary business expenses, as are administrative costs to the extent they constitute ordinary and necessary business expenses which are reasonable in amount.

Tax basis, depreciation and amortization

The tax basis of our assets, such as casing, tubing, tanks, pumping units and other similar property, will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference

 


 

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between the fair market value of our assets and their tax basis immediately prior to (i) this offering will be borne by our existing unitholders, and (ii) any other offering will be borne by our unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs incurred in selling our common units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may be able to amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and tax basis of our properties

The federal income tax consequences of the ownership and disposition of common units will depend in part on our estimates of the relative fair market values and the tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

DISPOSITION OF COMMON UNITS

Recognition of gain or loss

Gain or loss will be recognized on a sale of common units equal to the difference between the unitholder’s amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that unit will, in effect, become taxable income if the unit is sold at a price greater than the unitholder’s tax basis in that unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. A

 


 

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portion of this gain or loss, which may be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to assets giving rise to “unrealized receivables” or “inventory items” that we own. The term “unrealized receivables” includes potential recapture items, including depreciation, depletion, and IDC recapture. Ordinary income attributable to unrealized receivables and inventory items may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of units. A unitholder considering the purchase of additional units or a sale of units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and those Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

Ø   a short sale;

 

Ø   an offsetting notional principal contract; or

 

Ø   a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer who enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations between transferors and transferees

In general, our taxable income or loss will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to as the allocation date. However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the allocation date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

 


 

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Although simplifying conventions are contemplated by the Code and most publicly-traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations and there is no direct or indirect controlling authority on the issue. Accordingly, Ledgewood is unable to opine on the validity of this method of allocating income and deductions between unitholders although Ledgewood has advised us that our decision to use this method is a reasonable interpretation of the Treasury Regulations. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification requirements

A unitholder who sells any of his units, other than through a broker, generally is required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A person who purchases units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase, unless a broker or nominee will satisfy such requirement. We are required to notify the IRS of any such transfers of units and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may lead to the imposition of substantial penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker.

Constructive termination

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a year ending December 31, the closing of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

UNIFORMITY OF COMMON UNITS

Because we cannot match transferors and transferees of common units, we must maintain uniformity of the economic and tax characteristics of the common units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the common units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

 


 

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We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized book-tax disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Code. This method is consistent with the Treasury Regulations applicable to all of our depreciable property.

TAX-EXEMPT ORGANIZATIONS AND OTHER INVESTORS

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company, or “mutual fund,” is required to derive at least 90% of its gross income from certain permitted sources. Income from the ownership of units in a “qualified publicly-traded partnership” is generally treated as income from a permitted source. We expect that we will meet the definition of a qualified publicly-traded partnership.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Under rules applicable to publicly-traded partnerships, we will withhold tax, at the highest effective applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” that is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

Under a ruling issued by the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent the gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

 


 

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ADMINISTRATIVE MATTERS

Information returns and audit procedures

We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction.

We cannot assure you that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the tax matters partner for these purposes. The limited liability company agreement appoints our manager as our tax matters partner.

The tax matters partner will make some elections on our behalf and on behalf of unitholders. In addition, the tax matters partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The tax matters partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the tax matters partner. The tax matters partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the tax matters partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

Ø   the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

Ø   a statement regarding whether the beneficial owner is:

 

  Ø   a person that is not a United States person,

 

  Ø   a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

 


 

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  Ø   a tax-exempt entity;

 

Ø   the amount and description of units held, acquired or transferred for the beneficial owner; and

 

Ø   specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-related penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

Ø   for which there is, or was, “substantial authority,” or

 

Ø   as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders could result in that kind of an “understatement” of income for which no “substantial authority” exists, we would be required to disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty. More stringent rules would apply to an understatement of tax resulting from ownership of units if we were classified as a “tax shelter.” We believe we will not be classified as a tax shelter.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

Reportable transactions

If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses in excess of $2 million. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) is audited by the IRS. Please read “—Information Returns and Audit Procedures” above.

 


 

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Moreover, if we were to participate in a listed transaction or a reportable transaction (other than a listed transaction) with a significant purpose to avoid or evade tax, you could be subject to the following provisions of the American Jobs Creation Act of 2004:

 

Ø   accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-related Penalties,”

 

Ø   for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability, and

 

Ø   in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any reportable transactions.

STATE, LOCAL AND OTHER TAX CONSIDERATIONS

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business and own property in Pennsylvania, Ohio, New York and Tennessee. We may also own property or do business in other states in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we may do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, we anticipate that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Ledgewood has not rendered an opinion on the state local, or foreign tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax return that may be required.

 


 

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Underwriting

We are offering our common units described in this prospectus through the underwriters named below. UBS Securities LLC is the representative of the underwriters and the sole book-running manager of this offering. Subject to the terms and conditions of an underwriting agreement, which will be filed as an exhibit to the registration statement of which this prospectus forms a part, each of the underwriters has severally agreed to purchase the number of common units listed next to its name in the following table:

 

Underwriters   

Number of

common
units

UBS Securities LLC

  
Wachovia Capital Markets, LLC   
A.G. Edwards & Sons, Inc.   
RBC Capital Markets Corporation   
Friedman, Billings, Ramsey & Co.   
KeyBanc Capital Markets, a division of McDonald Investments, Inc.   
Credit Suisse Securities (USA) LLC   
Sanders Morris Harris Inc.   
Stifel, Nicolaus & Company, Incorporated   
    

Total

   6,325,000
    

The underwriting agreement provides that the underwriters must buy all of the common units if they buy any of them. However, the underwriters are not required to take or pay for the common units covered by the underwriters’ option to purchase additional common units described below.

Our common units and the common units to be sold upon the exercise of the underwriters’ option to purchase additional common units, if any, are offered subject to a number of conditions, including:

 

Ø   receipt and acceptance of our common units by the underwriters, and

 

Ø   the underwriters’ right to reject orders in whole or in part.

We have been advised by the representatives that the underwriters intend to make a market in our common units, but that they are not obligated to do so and may discontinue making a market at any time without notice.

OPTION TO PURCHASE ADDITIONAL COMMON UNITS

We have granted the underwriters an option to buy up to an aggregate 948,750 additional common units. This option may be exercised if the underwriters sell more than 6,325,000 common units in connection with this offering. The underwriters have 30 days from the date of this prospectus to exercise this option. If the underwriters exercise this option, they will each purchase additional common units approximately in proportion to the amounts specified in the table above.

COMMISSIONS AND DISCOUNTS

Common units sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount of up to $             per common unit from the initial public offering price. Any of these securities dealers may resell any common units purchased from the underwriters to other brokers or dealers at a discount of up to $             per common unit from the initial public offering price. If all the common units are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. Sales of common units made outside of the United States may

 


 

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be made by affiliates of the underwriters. Upon execution of the underwriting agreement, the underwriters will be obligated to purchase the common units at the prices and upon the terms stated therein, and, as a result, will thereafter bear any risk associated with changing the offering price to the public or other selling terms.

The following table shows the per unit and total underwriting discounts and commissions we will pay to the underwriters assuming both no exercise and full exercise of the underwriters’ option to purchase up to an additional 948,750 units.

 

      No exercise    Full exercise

Per unit

   $                 $             

Total

   $                 $             

We estimate that the total expenses of this offering payable by us, not including the underwriting discounts and commissions and structuring fee, will be approximately $1.5 million.

In addition, we will pay UBS Securities LLC a structuring fee of $            , or 0.75% of the gross proceeds of this offering and any exercise of the underwriters’ option to purchase additional common units, in consideration of advice rendered related to the limited liability company structure of this offering and the related transactions described in this prospectus.

NO SALES OF SIMILAR SECURITIES

We, our subsidiaries, our officers and directors, substantially all of our existing unitholders, including Atlas America, our manager and its affiliates, including the executive officers and directors of our manager, and the participants in our directed unit program have entered into lock-up agreements with the underwriters. Under these agreements, subject to certain exceptions, we and each of these persons may not, without the prior written approval of UBS Securities LLC, offer, sell, contract to sell or otherwise dispose of or hedge our common units or securities convertible into or exchangeable for our common units, enter into any swap or other agreement that transfers, in whole or in part, any of the economic consequences of ownership of the common units, make any demand for or exercise any right or file or cause to be filed a registration statement with respect to the registration of any common units or securities convertible, exercisable or exchangeable into common units or any of our other securities or publicly disclose the intention to do any of the foregoing. These restrictions will be in effect for a period of 180 days after the date of this prospectus. The lock-up period will be extended under certain circumstances where we release, or pre-announce a release of, our earnings or announce material news or a material event during the 18 days before or 16 days after the termination of the 180-day period in which case the restrictions described above will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

At any time and without public notice, UBS Securities LLC may, in its discretion, release all or some of the securities from these lock-up agreements. When determining whether or not to release common units from these restrictions, the primary factors that UBS Securities LLC will consider include the requesting unitholder’s reasons for requesting the release, the number of common units for which the release is being requested and the prevailing economic and equity market conditions at the time of the request. UBS Securities LLC has no present intent to release any of the securities from these lock-up agreements.

 


 

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INDEMNIFICATION

We and Atlas America have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act and liabilities incurred in connection with the directed unit program referred to below, and to contribute to payments that the underwriters may be required to make for these liabilities. If we are unable to provide this indemnification, we will contribute to payments the underwriters may be required to make with respect to those liabilities.

DIRECTED UNIT PROGRAM

At our request, certain of the underwriters have reserved up to 300,000 common units for sale at the initial public offering price to our officers and directors as well as the officers, directors and employees of our manager and certain other persons associated with us. The sales will be made by UBS Financial Services Inc., a selected dealer affiliated with UBS Securities LLC, through a directed unit program. The minimum investment amount for participation in the program is $2,500. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units before the effectiveness of the registration statement relating to this offering.

Any participant purchasing in excess of $100,000 worth of reserved common units will be prohibited from offering, selling, contracting to sell or otherwise disposing of the common units for a period of 180 days after the date of this prospectus.

LISTING

Our common units have been approved for listing, subject to official notice of issuance, on the New York Stock Exchange under the trading symbol “ATN.”

PRICE STABILIZATION, SHORT POSITIONS

In connection with this offering, the underwriters may engage in activities that stabilize, maintain or otherwise affect the price of our common units including:

 

Ø   stabilizing transactions;

 

Ø   short sales;

 

Ø   purchases to cover positions created by short sales;

 

Ø   imposition of penalty bids; and

 

Ø   syndicate covering transactions.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of our common units while this offering is in progress. These transactions may also include making short sales of our common units, which involves the sale by the underwriters of a greater number of common units than they are required to purchase in this offering, and purchasing

 


 

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common units on the open market to cover positions created by short sales. Short sales may be “covered” shorts, which are short positions in an amount not greater than the underwriters’ option to purchase additional common units referred to above, or may be “naked” shorts, which are short positions in excess of that amount.

The underwriters may close out any covered short position by either exercising their option to purchase additional common units, in whole or in part, or by purchasing common units in the open market. In making this determination, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through their option to purchase additional common units.

Naked short sales are in excess of the underwriters’ option to purchase additional common units. The underwriters must close out any naked short position by purchasing common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market that could adversely affect investors who purchased in this offering.

The underwriters also may impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased common units sold by or for the account of that underwriter in stabilizing or short covering transactions.

As a result of these activities, the price of our common units may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the underwriters at any time. The underwriters may carry out these transactions on the New York Stock Exchange, in the over-the-counter market or otherwise.

DETERMINATION OF OFFERING PRICE

Before this offering, there has been no public market for our common units. The initial public offering price will be determined by negotiation by us and the representatives of the underwriters. The principal factors to be considered in determining the initial public offering price include:

 

Ø   the information set forth in this prospectus and otherwise available to the representatives;

 

Ø   our history and prospects, and the history and prospects of the industry in which we compete;

 

Ø   our past and present financial performance and an assessment of the directors and officers of our manager;

 

Ø   our prospects for future earnings and cash flow and the present state of our development;

 

Ø   the general condition of the securities markets at the time of this offering;

 

Ø   the recent market prices of, and demand for, publicly-traded common units of generally comparable companies; and

 

Ø   other factors deemed relevant by the underwriters and us.

ELECTRONIC DISTRIBUTION

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in

 


 

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this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of units for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

DISCRETIONARY SALES

The underwriters have informed us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of units offered by them.

STAMP TAXES

If you purchase common units offered in this prospectus, you may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover page of this prospectus.

AFFILIATIONS

The underwriters and their affiliates may from time to time in the future engage in transactions with us and perform services for us in the ordinary course of their business. In addition, some of the underwriters have engaged in, and may in the future engage in, transactions with us and our predecessor and perform services for us in the ordinary course of their business.

Because the NASD views the common units offered hereby as interests in a direct participation program, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules. In no event will the maximum amount of compensation to be paid to NASD members in connection with this offering exceed 10%. Investor suitability with respect to the common units should be judged similarly to the suitability with respect to other securities that are listed for trading on the New York Stock Exchange or a national securities exchange.

 


 

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Legal matters

The validity of the common units and the description of federal income tax consequences in “Risk factors—Tax Risks to Unitholders” and “Material tax consequences” will be passed upon for us by Ledgewood, Philadelphia, Pennsylvania, and the validity of the common units will be passed upon for the underwriters by Vinson & Elkins L.L.P.

Engineers

The estimated reserve evaluations and related calculations of Wright & Company, Inc., independent petroleum engineering consultants, included in this prospectus have been included in reliance on the authority of that firm as experts in petroleum engineering.

Experts

The combined financial statements of Atlas America E&P Operations as of December 31, 2005 and September 30, 2005 and 2004 and for the three months ended December 31, 2005 and for each of the three years in the period ended September 30, 2005, and the balance sheet of Atlas Energy Resources, LLC dated as of July 14, 2006 have been audited by Grant Thornton LLP, independent registered public accounting firm, as indicated in their reports with respect thereto, and are included in this prospectus in reliance upon the authority of such firm as experts in giving such reports.

Where you can find more information

We have filed with the SEC under the Securities Act a registration statement on Form S-1 with respect to the common units offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all the information set forth in the registration statement or the exhibits and schedules which are part of the registration statement, portions of which are omitted as permitted by the rules and regulations of the SEC. Statements made in this prospectus regarding the contents of any contract or other document are summaries of the material terms of the contract or document. With respect to each contract or document filed as an exhibit to the registration statement, reference is made to the corresponding exhibit. For further information pertaining to us and the common units offered by this prospectus, reference is made to the registration statement, including the exhibits and schedules thereto, copies of which may be inspected without charge at the public reference facilities of the SEC at 100 F Street, N.E., Washington, D.C. 20549. Copies of all or any portion of the registration statement may be obtained from the SEC at prescribed rates. Information on the public reference facilities may be obtained by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains a web site that contains reports, proxy and information statements and other information that is filed through the SEC’s EDGAR system. The web site can be accessed at http://www.sec.gov.

 


 

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Index to Financial Statements

 

ATLAS ENERGY RESOURCES, LLC UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

  

Introduction

   F-2

Unaudited Pro Forma Combined Balance Sheet as of September 30, 2006

   F-3

Unaudited Pro Forma Combined Statement of Income for the nine months ended September 30, 2006

   F-4

Unaudited Pro Forma Combined Statement of Income for the three months ended December 31, 2005

   F-5

Unaudited Pro Forma Combined Statement of Income for the year ended September 30, 2005

   F-6

Notes to Unaudited Pro Forma Combined Financial Statements

   F-7

ATLAS AMERICA E&P OPERATIONS COMBINED FINANCIAL STATEMENTS

  

Report of Independent Registered Public Accounting Firm

   F-10

Combined Balance Sheets as of September 30, 2004, 2005, December 31, 2005 and September 30, 2006

   F-11

Combined Statements of Income for the years ended September 30, 2003, 2004 and 2005 and three months ended December 31, 2004 and 2005 and nine months ended September 30, 2005 and 2006

   F-12

Combined Statements of Comprehensive Income for the years ended September 30, 2003, 2004, 2005 and the three months ended December 31, 2004 and 2005 and nine months ended September 30, 2005 and 2006

   F-13

Combined Statements of Combined Equity for the years ended September 30, 2003, 2004, 2005 and the three months ended December 31, 2005 and nine months ended September 30, 2006

   F-14

Combined Statements of Cash Flows for the year ended September 30, 2003, 2004, 2005 and three months ended December 31, 2004 and 2005 and the nine months ended September 30, 2005 and 2006

   F-15

Notes to Combined Financial Statements

   F-16

ATLAS ENERGY RESOURCES, LLC BALANCE SHEET

  

Report of Independent Registered Public Accounting Firm

   F-36

Balance Sheets as of July 14, 2006 and September 30, 2006

   F-37

Note to Balance Sheets

   F-38

 

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ATLAS ENERGY RESOURCES, LLC

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

The unaudited pro forma combined financial statements of Atlas Energy Resources, LLC as of September 30, 2006, for the year ended September 30, 2005, the three months ended December 31, 2005 and for the nine months ended September 30, 2006 are based upon the historical combined financial position and results of operations of Atlas America E & P Operations. Upon the completion of its initial public offering, Atlas Energy Resources, LLC (“Atlas Energy Resources”) will own the subsidiaries and operate the businesses of Atlas America E & P Operations, other than the retained assets described in the notes to these financial statements. The contribution of assets to Atlas Energy Resources will be recorded at historical cost because it is considered to be a reorganization of entities under common control. Unless the context otherwise requires, references herein to Atlas Energy Resources include Atlas Energy Resources and its operating subsidiaries. The unaudited pro forma combined financial statements for Atlas Energy Resources have been derived from the historical combined financial statements of Atlas America E & P Operations set forth elsewhere in this prospectus and are qualified in their entirety by reference to such historical combined financial statements and related notes contained therein. The pro forma financial statements have been prepared on the basis that Atlas Energy Resources will be treated as a partnership for federal income tax purposes.

The unaudited pro forma balance sheet and the pro forma statements of income were derived by adjusting the historical combined financial statements of Atlas America E & P Operations. The adjustments are based upon currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma combined financial statements.

The unaudited pro forma combined financial statements are not necessarily indicative of the results that actually would have occurred if Atlas Energy Resources had assumed the operations of Atlas America E & P Operations on the dates indicated or the results that would be obtained in the future.

 

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September 30, 2006

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

(in thousands)

 

      Atlas America
E & P
Operations
historical
   Pro forma
adjustments
   Atlas
Energy
Resources
pro forma
ASSETS           

Current assets:

          

Cash and cash equivalents

   $ 56,606    $ 126,500     (a)    $ 5,106
        (8,855 )   (b)   
        (1,500 )   (c)   
        (116,145 )   (d)   
        (1,500 )   (g)   
        9,575     (f)   
        (9,575 )   (h)   
        (50,000 )   (i)   

Accounts receivable

     21,575      —       (e)      21,575

Unrealized hedge gain

     20,116      —            20,116

Prepaid expenses

     4,730      —            4,730
                        

Total current assets

     103,027      (51,500 )        51,527

Property and equipment, net

     249,986      —       (e)      249,986

Other assets

     22,807      1,500     (g)      24,307

Intangible assets, net

     5,431      —            5,431

Goodwill

     35,166      —            35,166
                        
   $ 416,417    $ (50,000 )      $ 366,417
                        

LIABILITIES AND COMBINED EQUITY

          

Current liabilities:

          

Current portion of long-term debt

   $ 52    $ —          $ 52

Accounts payable

     36,670      —            36,670

Liabilities associated with drilling contracts

     76,883      —            76,883

Advances from affiliates

     9,575      (9,575 )   (h)      —  
          

Accrued liabilities

     18,809      —            18,809
                        

Total current liabilities

     141,989      (9,575 )        132,414

Long term debt

     38      9,575     (f)      9,613

Unrealized hedge loss

     14,116      —            14,116

Asset retirement obligations

     20,307      —            20,307

Commitments and contingencies

          

Combined equity

     222,555      (116,145 )   (d)      172,555
        126,500     (a)   
        (8,855 )   (b)   
        (1,500 )   (c)   
        (50,000 )   (i)   

Accumulated other comprehensive income

     17,412      —            17,412
                        

Total equity

     239,967      (50,000 )        189,967
                        
   $ 416,417    $ (50,000 )      $ 366,417
                        

See accompanying notes to unaudited pro forma combined financial statements

 

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ATLAS ENERGY RESOURCES, LLC


 

NINE MONTHS ENDED SEPTEMBER 30, 2006

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

(in thousands, except for per unit data)

 

     

Atlas America

E & P Operations
historical

   Pro forma
adjustments
    Atlas Energy
Resources pro
forma
 

REVENUES

       

Gas and oil production

   $ 66,696    $ —       $ 66,696  

Well construction and completion

     135,329      —         135,329  

Administration and oversight

     8,487      —         8,487  

Well services

     9,498      —         9,498  

Gathering

     6,902      —         6,902  
                       

Total Revenues

     226,912      —         226,912  

COSTS AND EXPENSES

       

Gas and oil production and exploration

     12,506      —         12,506  

Well construction and completion

     117,677      —         117,677  

Well services

     5,540      —         5,540  

Gathering fee—Atlas Pipeline

     22,719      (15,817 )(n)     6,902  

Gathering

     159      (159 )(j)     —    

General and administrative

     15,387      575 (k)(o)     15,962  

Net expense reimbursement—affiliate

     1,041      —         1,041  

Depreciation, depletion and amortization

     16,311      —         16,311  
                       

Total operating expenses

     191,340      (15,401 )     175,939  

OTHER INCOME (EXPENSES)

       

Interest income

     653            653  

Interest expense

     —        (863 )(l)     (1,238 )
        (375 )(m)  

Other—net

     309      —         309  
                       

Total other income (expenses)

     962      (1,238 )     (276 )
                       

Net income before taxes

   $ 36,534    $ 14,163     $ 50,697  
                       

Net income per unit

        $ 1.35  
             

Weighted average units outstanding

          37,422,821  
             

See accompanying notes to unaudited pro forma combined financial statements

 

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ATLAS ENERGY RESOURCES, LLC


 

THREE MONTHS ENDED DECEMBER 31, 2005

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

(in thousands, except for per unit data)

 

      Atlas America
E & P Operations
historical
   Pro forma
adjustments
    Atlas Energy
Resources
pro forma
 

REVENUES

       

Gas and oil production

   $ 24,086    $ —       $ 24,086  

Well construction and completion

     42,145      —         42,145  

Administration and oversight

     2,964      —         2,964  

Well services

     2,561      —         2,561  

Gathering

     1,407      —         1,407  
                       

Total revenues

     73,163      —         73,163  

COSTS AND EXPENSES

       

Gas and oil production and exploration

     2,458      —         2,458  

Well construction and completion

     36,648      —         36,648  

Well services

     1,487      —         1,487  

Gathering fee—Atlas Pipeline

     7,930      (6,523 )(n)     1,407  

Gathering

     38      (38 )(j)     —    

General and administrative

     5,801      192 (k)(o)     5,993  

Net expense reimbursement-affiliate

     163      —         163  

Depreciation, depletion and amortization

     4,916      —         4,916  
                       

Total operating expenses

     59,441      (6,369 )     53,072  

OTHER INCOME (EXPENSES)

       

Interest income

     32            32  

Interest expense

     —        (288 )(l)     (413 )
        (125 )(m)  

Other-net

     25      —         25  
                       

Total other income (expenses)

     57      (413 )     (356 )
                       

Net income before taxes

   $ 13,779    $ 5,956     $ 19,735  
                       

Net income per unit

        $ 0.53  
             

Weighted average units outstanding

          37,422,821  
             

See accompanying notes to unaudited pro forma combined financial statements

 

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ATLAS ENERGY RESOURCES, LLC


 

YEAR ENDED SEPTEMBER 30, 2005

UNAUDITED PRO FORMA COMBINED STATEMENT OF INCOME

(in thousands, except for per unit data)

 

      Atlas America
E & P Operations
historical
    Pro forma
adjustments
    Atlas Energy
Resources
pro forma
 

REVENUES

      

Gas and oil production

   $ 63,499     $ —       $ 63,499  

Well construction and completion

     134,338       —         134,338  

Administration and oversight

     9,590       —         9,590  

Well services

     9,552       —         9,552  

Gathering

     4,359       —         4,359  
                        

Total revenues

     221,338       —         221,338  

COSTS AND EXPENSES

      

Gas and oil production and exploration

     9,070       —         9,070  

Well construction and completion

     116,816       —         116,816  

Well services

     5,167       —         5,167  

Gathering fee—Atlas Pipeline

     21,929       (17,570 )(n)     4,359  

Gathering

     52       (52 )(j)     —    

General and administrative

     12,297       767 (k)(o)     13,064  

Net expense reimbursement-affiliate

     602       —         602  

Depreciation, depletion and amortization

     14,061       —         14,061  
                        

Total operating expenses

     179,994       (16,855 )     163,139  

OTHER INCOME (EXPENSES)

      

Interest income

     317       —         317  

Interest expense

     —         (950 )(l)     (1,450 )
       (500 )(m)  

Other-net

     (238 )     —         (238 )
                        

Total other income (expenses)

     79       (1,450 )     (1,371 )
                        

Net income before taxes

   $ 41,423     $ 15,405     $ 56,828  
                        

Net income per unit

       $ 1.52  
            

Weighted average units outstanding

         37,442,821  
            

See accompanying notes to unaudited pro forma combined financial statements

 

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ATLAS ENERGY RESOURCES, LLC


 

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

1.    Basis of Presentation, the Offering and Other Transactions

The historical financial information is derived from the historical combined financial statements of Atlas America E & P Operations. The pro forma adjustments have been prepared as if the transactions to be effected at the closing of this offering had taken place on September 30, 2006, in the case of the pro forma balance sheet, or as of October 1, 2004, in the case of the pro forma statement of income for the year ended September 30, 2005, as of October 1, 2005 for the three months ended December 31, 2005 and as of January 1, 2006 for the nine months ended September 30, 2006.

The pro forma financial statements reflect the following transactions:

 

·   the contribution of assets by Atlas America to Atlas Energy Resources in exchange for the issuance of 30,299,365 common units, 748,456 Class A units and the management incentive interests;

 

·   the sale by Atlas Energy Resources of 6,325,000 common units to the public in this offering;

 

·   the issuance by Atlas Energy Resources of 50,000 common units to Richard D. Weber;

 

·   the payment of estimated underwriting commissions of $8.9 million and other offering expenses totalling $1.5 million;

 

·   the net proceeds received from borrowings of $9.6 million under our new credit facility;

 

·   the distribution to Atlas America of the net proceeds from this offering and from borrowings under the new credit facility;

 

·   the distribution to Atlas America of approximately $50.0 million, the remaining proceeds from Atlas Pipeline Holdings, L.P.’s initial public offering;

 

·   the retention by Atlas America of a small gathering system; and

 

·   the execution of the contribution agreement described under “Certain Relationships and Related Transactions—Agreements Governing the Transactions—The Contribution Agreement,” pursuant to which Atlas America will assume our obligation to pay gathering fees to Atlas Pipeline.

2.    Pro Forma Adjustments and Assumptions

 

(a)   Reflects the gross proceeds to Atlas Energy Resources of $126.5 million from the issuance and sale of 6,325,000 common units at an assumed initial public offering price of $20.00 per unit.

 

(b)   Reflects the payment of estimated underwriting commissions of $8.9 million, which will be allocated to the public common units.

 

(c)   Reflects the payment of $1.5 million for the estimated costs associated with the offering, which will be allocated to the public common units.

 

(d)   Reflects the payment of the net proceeds from the initial public offering to Atlas America.

 

(e)   Reflects the retention by Atlas America of a gathering system with no book value.

 

(f)   Reflects $9.6 million of borrowings under the new credit facility and payment of this amount to Atlas America to eliminate advances from it.

 

(g)   Reflects estimated deferred financing costs of $1.5 million associated with the new credit facility.

 

(h)   Reflects the payment to Atlas America to eliminate advances from it.

 

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ATLAS ENERGY RESOURCES, LLC


NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

(i)   Reflects the payment to Atlas America of the remaining proceeds from Atlas Pipeline Holdings’ initial public offering.

 

(j)   Reflects the removal of expenses associated with the gathering system retained by Atlas America.

 

(k)   Reflects additional expense related to amortization of incentive compensation for our president. Upon the completion of this offering, pursuant to his employment agreement with Atlas America, our president will receive approximately 50,000 restricted common units and options representing a 1% membership interest in us.

 

(l)   Reflects the interest expense related to the borrowings described in (f) above. The interest expense is based on average interest rates of 6.8%, 6.8% and 4.7% for the nine months ended September 30, 2006, three months ended December 31, 2005 and year ended September 30, 2005, respectively, which reflects the average borrowing rates experienced by Atlas America during those periods. Atlas Energy Resources used historical interest rates obtained by Atlas America because it believes that it will enter into a credit facility with terms substantially the same as the terms of Atlas America’s credit facility. An increase or decrease in interest rates of 1% would have changed pro forma interest expense by $72,000 for the nine months ended September 30, 2006, $24,000 for the three months ended December 31, 2005 and $96,000 for fiscal 2005.

 

(m)   Reflects the amortization of deferred financing costs related to Atlas Energy Resources’ new credit facility.

 

(n)   Reflects the reduction to gathering fees resulting from the retention by Atlas America of the obligation to pay the difference between gathering fees paid to us by the investment partnerships and gathering fees due to Atlas Pipeline under the gas gathering agreement. Historically, the gathering fees we received from the partnerships were insufficient to cover the gathering expenses paid to Atlas Pipeline. After the closing of this offering, pursuant to the terms of our contribution agreement with Atlas America, we will pay Atlas America the gathering revenues we receive from the partnerships and Atlas America will pay all amounts due to Atlas Pipeline. Accordingly, our gathering revenues and expenses from the partnership management segment will net to $0. We also pay our proportionate share of gathering fees based on our percentage interest in the well, which are included in gas and oil production and exploration expense.

 

(o)   No adjustment has been made to general and administrative expenses to record approximately $500,000 of annual estimated costs associated with Schedule K-1 preparation and distribution. All other public entity general and administrative costs are included in the historical operating results.

3.    Pro Forma Net Income Per Unit

Pro forma net income per unit is determined by dividing the pro forma net income by the number of Class A and common units expected to be outstanding at the closing of the offering. For purposes of this calculation, the number of units assumed to be outstanding was 37,442,821. All units were assumed to have been outstanding for the entire period presented. Basic and diluted pro forma net income per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of Atlas Energy Resources. To the extent that the quarterly distributions exceed certain targets, Atlas Energy Resources’ manager is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to Atlas Energy Resources’ manager than to the holders of common units. The pro forma net income per unit calculations assume that no incentive distributions were made to Atlas Energy Resources’ manager because no such distribution would have been payable.

 

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ATLAS ENERGY RESOURCES, LLC


 

Staff Accounting Bulletin 1:B:3 requires that certain distributions to owners prior to or coincident with an initial public offering be considered as distributions in contemplation of that offering. We anticipate paying the net proceeds of this offering of approximately $116.1 million, after payment of offering expenses, to Atlas America as reimbursement of capital expenditures incurred by it on our behalf and partial consideration for its contribution of assets to us. In addition, our pro forma financial statements reflect approximately $9.6 million of indebtedness under a revolving credit facility that we expect to enter into upon the completion of this offering in order to reimburse Atlas America for other advances made on our behalf. Assuming additional common units and Class A units were issued to give effect to this distribution, pro forma net income per unit would have been $1.20, $.0.46 and $1.34 for the nine months ended September 30, 2006, three months ended December 31, 2005 and the year ended September 30, 2005, respectively.

 

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Table of Contents

 

Report of Independent Registered Public Accounting Firm

Board of Directors

Atlas America, Inc

We have audited the accompanying combined balance sheets of Atlas America E & P Operations (the “Company”—see Note 1 to the combined financial statements) as of December 31, 2005, September 30, 2005 and 2004 and the related combined statements of income, comprehensive income, equity and cash flows for the three months in the period ended December 31, 2005 and for each of the three years in the period ended September 30, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. 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 combined financial statements referred to above present fairly, in all material respects, the financial position of Atlas America E & P Operations as of December 31, 2005, September 30, 2005 and 2004, and the results of its operations and cash flows for each of the three years in the period ended September 30, 2005 and for the three months ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Cleveland, Ohio

November 20, 2006

 

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ATLAS AMERICA E & P OPERATIONS


 

COMBINED BALANCE SHEETS

(in thousands)

 

    

September 30,

2004

  

September 30,

2005

  

December 31,

2005

   

September 30,

2006

                     (unaudited)

ASSETS

          

Current assets:

          

Cash and cash equivalents

   $ 172    $ 6,246    $ 20,918     $ 56,606

Accounts receivable

     12,772      17,714      25,282       21,575

Unrealized hedge gain

          —        —         20,116

Prepaid expenses

     1,625      3,466      3,318       4,730
                            

Total current assets

     14,569      27,426      49,518       103,027

Property and equipment, net

     140,779      201,263      214,701       249,986

Other assets

     697      237      9,577       22,807

Intangible assets, net

     7,243      6,310      6,090       5,431

Goodwill

     35,166      35,166      35,166       35,166
                            
   $ 198,454    $ 270,402    $ 315,052     $ 416,417
                            

LIABILITIES AND COMBINED EQUITY

          

Current liabilities:

          

Current portion of long-term debt

   $ 339    $ 59    $ 88     $ 52

Accounts payable

     19,880      24,220      41,160       36,670

Liabilities associated with drilling contracts

     29,375      60,971      70,514       76,883

Advances from affiliates

     30,008      13,897      4,257       9,575

Accrued liabilities

     4,421      7,440      11,991       18,809
                            

Total current liabilities

     84,023      106,587      128,010       141,989

Long term debt

     81      22      68       38

Unrealized hedge loss

          —        13,956       14,116

Asset retirement obligations

     4,889      17,651      18,499       20,307

Commitments and contingencies (Note 7)

          

Combined equity

     109,461      146,142      158,183       222,555

Accumulated other comprehensive income

          —        (3,664 )     17,412
                            

Total equity

     109,461      146,142      154,519       239,967
                            
   $ 198,454    $ 270,402    $ 315,052     $ 416,417
                            

See accompanying notes to combined financial statements

 

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ATLAS AMERICA E & P OPERATIONS


 

COMBINED STATEMENTS OF INCOME

(in thousands)

 

   

Years Ended September 30,

    Three Months Ended
December 31,
  Nine Months Ended
September 30,
    2003   2004   2005       2004       2005     2005     2006
                  (unaudited)       (unaudited)

REVENUES

             

Gas and oil production

  $ 38,639   $ 48,526   $ 63,499     $ 14,659   $ 24,086   $ 48,840     $ 66,696

Well construction and completion

    52,879     86,880     134,338       30,558     42,145     103,780       135,329

Administration and oversight

    5,090     8,396     9,590       2,156     2,964     7,436       8,487

Well services

    7,635     8,430     9,552       2,248     2,561     7,304       9,498

Gathering

    3,898     4,191     4,359       1,158     1,407     3,200       6,902
                                             

Total revenues

    108,141     156,423     221,338       50,779     73,163     170,560       226,912

COSTS AND EXPENSES

             

Gas and oil production and exploration

    8,486     8,838     9,070       1,802     2,458     7,268       12,506

Well construction and completion

    45,982     75,548     116,816       26,573     36,648     90,243       117,677

Well services

    3,773     4,398     5,167       1,191     1,487     3,976       5,540

Gathering

    29     53     52       21     38     31       159

Gathering fee—Atlas Pipeline

    14,564     17,189     21,929       5,281     7,930     16,649       22,719

General and administrative

    8,390     10,159     12,297       2,147     5,801     10,151       15,387

Net expense reimbursement-affiliate

    1,400     1,050     602       213     163     389       1,041

Depreciation, depletion and amortization

    9,938     12,064     14,061       3,165     4,916     10,895       16,311
                                             

Total operating expenses

    92,562     129,299     179,994       40,393     59,441     139,602       191,340
                                             

Operating income

    15,579     27,124     41,344       10,386     13,722     30,958       35,572

OTHER INCOME (EXPENSES)

             

Interest income

    251     250     317       1     32     316       653

Other—net

    107     194     (238 )     1     25     (239 )     309
                                             

Total other income

    358     444     79       2     57     77       962
                                             

Net income before taxes

  $ 15,937   $ 27,568   $ 41,423     $ 10,388   $ 13,779   $ 31,035     $ 36,534
                                             

See accompanying notes to combined financial statements

 

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ATLAS AMERICA E & P OPERATIONS


COMBINED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

 

 

    Years Ended September 30,   Three Months Ended
December 31,
    Nine Months Ended
September 30,
 
    2003     2004   2005   2004   2005     2005   2006  
                  (unaudited)         (unaudited)  

Net income before taxes

  $ 15,937     $ 27,568   $ 41,423   $ 10,388   $ 13,779     $ 31,035   $ 36,534  

Other comprehensive income:

             

Unrealized holding gains (losses) on hedging contracts

    (765 )     —       —       —       (3,664 )     —       26,016  

Less: reclassification adjustment for (gains) losses realized in net income

    1,108       —       —       —       —         —       (4,940 )
                                               
    343       —       —       —       (3,664 )     —       21,076  
                                               

Comprehensive income

  $ 16,280     $ 27,568   $ 41,423   $ 10,388   $ 10,115     $ 31,035   $ 57,610  
                                               

See accompanying notes to combined financial statements

 

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ATLAS AMERICA E & P OPERATIONS


 

COMBINED STATEMENTS OF COMBINED EQUITY

(in thousands)

 

      Accumulated
Other
Comprehensive
Income (Loss)
    Net
Affiliate
Investment
    Combined
Equity
 

Balance, October 1, 2002

   $ (343 )   $ 67,741     $ 67,398  

Net change in affiliate advances

     —         18,353       18,353  

Other comprehensive income

     343       —         343  

Net income

     —         15,937       15,937  
                        

Balance, September 30, 2003

     —         102,031       102,031  

Net change in affiliate advances

     —         (20,138 )     (20,138 )

Net income

     —         27,568       27,568  
                        

Balance, September 30, 2004

     —         109,461       109,461  

Net change in affiliate advances

     —         (4,742 )     (4,742 )

Net income

     —         41,423       41,423  
                        

Balance, September 30, 2005

     —         146,142       146,142  

Net change in affiliate advances

     —         (1,738 )     (1,738 )

Other comprehensive income

     (3,664 )     —         (3,664 )

Net income

     —         13,779       13,779  
                        

Balance, December 31, 2005

     (3,664 )     158,183       154,519  

Net change in affiliate advances

     —         27,838       27,838  

Other comprehensive income

     21,076       —         21,076  

Net income

     —         36,534       36,534  
                        

Balance September 30, 2006 (unaudited)

   $ 17,412     $ 222,555     $ 239,967  
                        

See accompanying notes to combined financial statements

 

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Table of Contents

ATLAS AMERICA E & P OPERATIONS


 

COMBINED STATEMENTS OF CASH FLOWS

(in thousands)

 

    Years Ended September 30,     Three Months Ended
December 31,
   

Nine Months Ended

September 30,

 
    2003     2004     2005       2004         2005       2005     2006  
                      (unaudited)           (unaudited)  

CASH FLOWS FROM OPERATING ACTIVITIES:

             

Net income before taxes

  $ 15,937     $ 27,568     $ 41,423     $ 10,388     $ 13,779     $ 31,035     $ 36,534  

Adjustments to reconcile net income to net cash provided by operating activities:

             

Depreciation, depletion and amortization

    9,938       12,064       14,061       3,165       4,916       10,895       16,311  

Write down of note receivable

    —         —         487         —           487       —    

Non-cash compensation on long-term incentive plans

    6       64       300       39       393       261       1,251  

Gain on asset dispositions

    (11 )     (43 )     (52 )     (23 )     (2 )     (29 )     (35 )

Advances (to) affiliates

    (22,454 )     (11,517 )     (25,081 )     (16,155 )     (11,813 )     (8,342 )     (42,419 )

Changes in operating assets and liabilities:

             

(Increase) decrease in accounts receivable

    1,257       377       (4,942 )     (2,020 )       (4,378)     (2,922 )     573  

(Increase) decrease in prepaid expenses

    (545 )     2,576       2,392       (889 )     149       3,281       (1,365 )

Increase in accounts payable

    3,268       4,460       4,340       5,917       16,940       (1,577 )     (4,490 )

Increase in liabilities associated with drilling contracts

    17,209       7,922       31,596       23,234       9,543       8,361       6,369  

Increase (decrease) in other operating assets and liabilities

    (4,240 )     (948 )     920       (1,257 )     2,256       1,595       2,457  
                                                       

Net cash provided by operating activities

    20,365       42,523       65,444       (22,399 )     31,783       43,045       15,186  

CASH FLOWS FROM INVESTING ACTIVITIES:

             

Capital expenditures

    (22,607 )     (33,252 )     (59,124 )     (11,645 )     (17,187 )     (47,479 )     (54,076 )

Proceeds from sale of assets

    179       218       111       35       3       76       43  

Decrease (increase) in other assets

    316       325       (37 )     19       (1 )     (56 )     107  
                                                       

Net cash used in investing activities

    (22,112 )     (32,709 )     (59,050 )     (11,591 )     (17,185 )     (47,459 )     (53,926 )

CASH FLOWS FROM FINANCING ACTIVITIES:

             

Borrowings

    228       282       —           91       —         —    

Principal payments on borrowings

    (194 )     (56 )     (339 )     (35 )     (17 )     (304 )     (65 )

Issuance of common stock by AAI

    —         36,991       —           —         —         —    

Dividend to Resource America, Inc.

    —         (52,133 )     —           —         —         —    

Issuance of common units by AHD

                74,493  

Decrease in other assets

    —         —         19           19    
                                                       

Net cash provided by (used in) financing activities

    34       (14,916 )     (320 )     (35 )     74       (285 )     74,428  
                                                       

Increase (decrease) in cash and cash equivalents

    (1,713 )     (5,102 )     6,074       10,773       14,672       (4,699 )     35,688  

Cash and cash equivalents at beginning of period

    6,987       5,274       172       172       6,246       10,945       20,918  
                                                       

Cash and cash equivalents at end of period

  $ 5,274     $ 172     $ 6,246     $ 10,945     $ 20,918     $ 6,246     $ 56,606  
                                                       

See accompanying notes to combined financial statements

 

F-15


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS

 

NOTE 1—DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION

Atlas America E & P Operations (the Company) is engaged primarily in the development and production of natural gas and, to a lesser extent, oil in the western New York, eastern Ohio, western Pennsylvania and Tennessee region of the Appalachian Basin for its own account and for investors through the sponsorship and management of tax-advantaged investment partnerships, in which it also co-invests.

The accompanying combined financial statements and related notes of the Company are prepared in connection with the proposed initial public offering of limited liability company units in Atlas Energy Resources, LLC (“Atlas Energy Resources”) and include subsidiaries of Atlas America, Inc. (“AAI”) which hold the oil and gas exploration and production assets, liabilities, equity and operations of AAI. AAI intends to transfer substantially all of the assets, liabilities and operations of its natural gas and oil development and production subsidiaries to Atlas Energy Resources and make an initial public offering of a minority interest of approximately 20% in Atlas Energy Resources.

AAI was incorporated in Delaware on September 27, 2000 and in May 2004 it completed an initial public offering. AAI trades under the symbol ATLS on the NASDAQ system. In June 2005 Resource America, Inc. (“RAI”) spun off its remaining interest in AAI to its shareholders.

The combined financial statements of the Company have been prepared from the separate records maintained by AAI and may not necessarily be indicative of the conditions that would have existed or the results of operations if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various entities comprising the Company, AAI’s net investment in the Company is shown as combined equity in the combined financial statements. Transactions between the Company and other AAI operations have been identified in the combined statements as transactions between affiliates (see Note 5). In accordance with established practice in the oil and gas industry, the Company includes its pro rata share of assets, liabilities, revenues and costs and expenses of the investment partnerships in which it has an interest.

The combined balance sheets as of September 30, 2006, the combined statements of income, comprehensive income, equity and cash flows as of and for the nine months ended September 30, 2006 and 2005 and the combined statements of income and cash flows for the three months ended December 31, 2004 are unaudited. These unaudited interim combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements. All significant intercompany balances and transactions within the Company have been eliminated.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

 

F-16


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

Comprehensive Income

Comprehensive income 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. These changes, other than net income, are referred to as “other comprehensive income” and for the Company include only changes in the fair value of unrealized hedging gains and losses.

Accounts Receivables and Allowance for Possible Losses

In evaluating its allowance for possible losses, the Company performs ongoing credit evaluations of its customers and adjusts credit limits based upon payment history and the customer’s current creditworthiness, as determined by the Company’s review of its customer’s credit information. The Company extends credit on an unsecured basis to many of its energy customers. At September 30, 2004 and 2005, December 31, 2005 and September 30, 2006, the Company’s credit evaluation indicated that it has no need for an allowance for possible losses.

Property and Equipment

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

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

Land, buildings and improvements

   10-40 years

Furniture and equipment

   3-7 years

Other

   3-10 years

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

 

    

At September 30,

2004

   

At September 30,

2005

   

At December 31,
2005

   

At September 30,

2006

 
          
     (in thousands)  
                          

Mineral interests:

        

Proved properties

   $ 2,544     $ 2,852     $ 2,308     $ 1,443  

Unproved properties

     1,002       1,002       1,002       1,002  

Wells and related equipment

     184,046       255,879       273,855       324,079  

Land, building and improvements

     4,055       4,140       4,146       4,153  

Support equipment

     2,891       3,644       4,173       5,163  

Other

     3,588       4,051       4,173       4,583  
                                
     198,126       271,568       289,657       340,423  

Accumulated depreciation, depletion and amortization:

        

Oil and gas properties

     (54,087 )     (66,537 )     (71,059 )     (86,150 )

Other

     (3,260 )     (3,768 )     (3,897 )     (4,287 )
                                
     (57,347 )     (70,305 )     (74,956 )     (90,437 )
                                
   $ 140,779     $ 201,263     $ 214,701     $ 249,986  
                                

 

F-17


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

Oil and Gas Properties

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

The Company’s long-lived assets are 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. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization and abandonment is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on the Company’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. The Company estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. If the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair market value, (as determined by discounted future cash flows) and the carrying value of the assets.

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.

Asset Retirement Obligations

The fair values of asset retirement obligations are recognized in the period they are incurred. Asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities and include costs to dismantle and relocate or dispose of production equipment, gathering systems, wells and related structures. Estimates are based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future and federal and state regulatory requirements. The Company does not provide for a market risk premium associated with asset retirement obligations because a reliable estimate cannot be determined.

Fair Value of Financial Instruments

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

For receivables and payables, the carrying amounts approximate fair value because of the short maturity of these instruments.

 

F-18


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

 

For derivatives the carrying value approximates fair value because the Company marks to market all derivatives.

For debt the carrying value approximates fair value because of the substantially short maturity of these instruments.

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 September 30, 2006, December 31, 2005 and September 30, 2005, the Company had $62.2 million, $27.4 million and $11.8 million in deposits at various banks, of which $61.6 million, $26.7 million and $11.2 million, respectively, was over the insurance limit of the Federal Deposit Insurance Corporation. No losses have been experienced on such investments.

Derivative Instruments

The Company applies the provisions of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and its various amendments (“SFAS 133”). SFAS 133 requires each derivative instrument to be recorded in the balance sheet as either an asset or liability measured at fair value. Changes in a derivative instrument’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. All derivative activity reflected in the combined financial statements was transacted by AAI with third parties and allocated to the Company.

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 for environmental contingencies 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 types of environmental contingencies. For the twelve months ended September 30, 2006 and three years ended September 30, 2005, the Company had no environmental contingencies requiring specific disclosure or the recording of a liability.

Revenue Recognition

The Company conducts certain energy activities through, and a portion of its revenues are attributable to, investment partnerships. The Company contracts with the investment partnerships to drill partnership wells. The contracts require that the investment partnerships must pay the Company 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, the Company classifies the difference between the contract payments it has received and the revenue earned as a current liability.

 


 

F-19


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

The Company recognizes gathering revenues at the time the natural gas is delivered.

The Company recognizes well services revenues at the time the services are performed.

The Company is entitled to receive administration and oversight fees according to the respective partnership agreements. The Company recognizes such fees as income when services are performed.

The Company records the income from the working interests and overriding royalties of wells in which it owns an interest when the gas and oil are delivered.

Because there are timing differences between the delivery of natural gas and oil and the Company’s receipt of a delivery statement, the Company has unbilled revenues. These revenues are accrued based upon volumetric data from the Company’s records and the Company’s estimates of the related transportation and compression fees which are, in turn, based upon applicable product prices. The Company had unbilled trade receivables at September 30, 2004 and 2005, December 31, 2005 and September 30, 2006 of $11.0 million, $16.0 million, $19.5 million and $18.9 million, respectively, which are included in Accounts Receivable on its Combined Balance Sheets.

Income Taxes

No provision for income taxes is made in the Company’s combined financial statements because the taxable income or loss of the Company will be included in the income tax returns of the individual members.

A reconciliation between the statutory federal income tax rate and the Company’s pro forma effective income tax rate as if the Company had computed income taxes is as follows:

 

 

    

Year Ended

September 30,

2005

   

Three Months

Ended

December 31,

2005

   

Nine Months
Ended

September 30,

2006

 
        

Statutory rate

   35 %   35 %   35 %

Statutory depletion

   (1 )   (1 )   (1 )

Non-conventional fuel credit

   —       —       —    

State income tax, net of federal benefit

   2     3     5  
                  
   36 %   37 %   39 %
                  

The following table reconciles net income before taxes to pro forma federal taxable income for the periods indicated (in thousands, unaudited):

 

    

Year Ended

September 30,

2005

   

Three Months

Ended

December 31,

2005

   

Nine Months
Ended

September 30,

2006

 
        

Net income before taxes

   $ 41,423     $ 13,779     $ 36,534  

Depreciation, depletion and amortization for tax reporting purposes

     (10,981 )     (3,206 )     10,765  

Deferred revenues

     3,061       (130 )     2,959  

Accrued expenses

     (29 )     (255 )     (1,877 )

Other

     32       257       419  
                        

Pro forma federal taxable income

   $ 33,506     $ 10,445     $ 48,800  
                        

The Company’s financial reporting bases of its net assets exceeded the tax bases of its net assets by $108.6 million, $108.3 million and $117.1 million at September 30, 2005, December 31, 2005 and September 30, 2006, respectively.

 

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Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

The following table details pro forma net income reflecting a tax provision calculated on a separate return basis (in thousands):

 

    

Year Ended

September 30,

2005

   

Three Months

Ended

December 31,

2005

   

Nine Months
Ended

September 30,

2006

 
        

Net income before taxes

   $ 41,423     $ 13,779     $ 36,534  

Tax provision

     (14,912 )     (5,056 )     (14,313 )
                        

Pro forma net income

   $ 26,511     $ 8,723     $ 22,221  
                        

Recently Issued Financial Accounting Standards

In September 2006, the SEC staff issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (“SAB 108”). SAB 108 was issued to provide consistency in how registrants quantify financial statement misstatements. The Company is required to and will initially apply SAB 108 in connection with the preparation of its annual financial statements for the year ending December 31, 2006. The Company does not expect the application of SAB 108 to have a material effect on its financial position and results of operations.

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurement” (“SFAS 157”). SFAS 157 addresses the need for increased consistency in fair value measurements, defining fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. It also establishes a framework for measuring fair value and expands disclosure requirements. SFAS 157 is effective for the Company beginning January 1, 2008. The Company is currently evaluating the impact of the adoption of SFAS 157 on its financial position and results of operations.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements and provides guidance on the recognition, de-recognition and measurement of benefits related to an entity’s uncertain tax positions. FIN 48 is effective for the Company beginning January 1, 2007. The Company is currently evaluating the impact of the adoption of FIN 48 on its financial position and results of operations.

In May 2005, the FASB issued Statement No. 154, “Accounting Changes and Error Corrections” (“SFAS 154”). SFAS 154 requires retrospective application to prior periods’ financial statements of changes in accounting principle. It also requires that the new accounting principle be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable and that a corresponding adjustment be made to the opening balance of retained earnings for that period rather than being reported in an income statement. The statement will be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Company’s financial position or results of operations.

 

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Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” or FIN 47, which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement cost will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in Statement No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement.

Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 was effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this interpretation is encouraged. The Company is currently evaluating the impact of the adoption of FIN 47 on its financial position and results of operations.

In April 2005, the FASB issued FASB Staff Position (“FSP”) No. 19-1, “Accounting for Suspended Well Costs.” This staff position amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” and provides guidance about exploratory well costs to companies which use the successful efforts method of accounting. The position states that exploratory well costs should continue to be capitalized if: 1) a sufficient quantity of reserves are discovered in the well to justify its completion as a producing well and 2) sufficient progress is made in assessing the reserves and the well’s economic and operating feasibility. If the exploratory well costs do not meet both of these criteria, these costs should be expensed, net of any salvage value. Additional annual disclosures are required to provide information about management’s evaluation of capitalized exploratory well costs. In addition, the FSP requires annual disclosure of: 1) net changes from period to period of capitalized exploratory well costs for wells that are pending the determination of proved reserves, 2) the amount of exploratory well costs that have been capitalized for a period greater than one year after the completion of drilling and 3) an aging of exploratory well costs suspended for greater than one year with the number of wells it related to. Further, the disclosures should describe the activities undertaken to evaluate the reserves and the projects, the information still required to classify the associated reserves as proved and the estimated timing for completing the evaluation. The guidance in the FSP was required to be applied to the first reporting period beginning after April 4, 2005 on a prospective basis to existing and newly capitalized exploratory well costs. The application of the FSP did not have a significant impact on the Company’s financial position or results of operations.

 

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Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

NOTE 3—OTHER ASSETS, INTANGIBLE ASSETS AND GOODWILL

Other Assets

The following table provides information about other assets at the dates indicated:

 

    

At September 30,

2004

  

At September 30,

2005

  

At December 31,

2005

  

At September 30,

2006

     (in thousands)

Long-term hedge receivable from Partnerships

   $    $ —      $ 9.340    $ 1,156

Long-term hedge receivable from AAI

          —        —        21,521

Investments

     622      102      102      —  

Security deposits

     75      120      125      127

Other

          15      10      3
                           
   $ 697    $ 237    $ 9,577    $ 22,807
                           

Long-term hedge receivable from Partnerships represents the portion of the long-term unrealized hedge loss on contracts allocated to the Company by AAI that has been reallocated to the Partnerships. Long-term hedge receivable from AAI represents the amounts due from AAI for the unrealized hedge gains on contracts allocated to the Company by AAI.

Intangible Assets

Included in intangible assets are partnership management and operating contracts acquired through previous acquisitions which were recorded at fair value on their acquisition dates. The Company amortizes contracts acquired on the declining balance and straight-line methods, over their respective estimated lives, ranging from five to thirteen years. Amortization expense for these contracts for the years ended September 30, 2004 and 2005 and the three months ended December 31, 2004 and 2005 were $1.0 million, $933,000, $233,000 and $220,000, respectively. Amortization expense for these contracts for the nine months ended September 30, 2005 and 2006 was $467,000 and $659,000, respectively.

The aggregate estimated annual amortization expense of customer and partnership management and operating contracts for the next five years ending September 30 is as follows: 2006—$879,000; 2007—$831,000; 2008—$788,000; 2009—$751,000 and 2010—$718,000.

The following table provides information about intangible assets at the dates indicated:

 

    

At September 30,

2004

   

At September 30,

2005

    At December 31,
2005
   

At September 30,

2006

 
     (in thousands)  

Cost

   $ 14,343     $ 14,343     $ 14,343     $ 14,343  

Accumulated amortization

     (7,100 )     (8,033 )     (8,253 )     (8,912 )
                                
   $ 7,243     $ 6,310     $ 6,090     $ 5,431  
                                

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

Goodwill

The Company applies the provisions of SFAS No. 142 (“SFAS 142”) “Goodwill and Other Intangible Assets,” which requires that goodwill no longer be amortized, but instead evaluated for impairment at least annually. The evaluation of impairment under SFAS 142 requires the use of projections, estimates and assumptions as to the future performance of the Company’s operations, including anticipated future revenues, expected future operating costs and the discount factor used. Actual results could differ from projections, resulting in revisions to the Company’s assumptions and, if required, recognition of an impairment loss. The Company’s evaluation of goodwill at September 30, 2005 indicated there was no impairment loss and no impairment indicators arose during the twelve months ended September 30, 2006. The Company will continue to evaluate its goodwill at least annually or when impairment indicators arise, and will reflect the impairment of goodwill, if any, within the consolidated statements of income in the period in which the impairment is indicated.

NOTE 4—ASSET RETIREMENT OBLIGATIONS

The Company recognizes an estimated liability for the plugging and abandonment of its oil and gas wells and equipment whenever 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 assets and allocated to expense using the units-of-production method. To the extent future revisions to these assumptions impact the fair value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and gas properties.

The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserve estimates, external estimates as to the cost to plug and abandon the wells in the future, inflation factors and legal regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The $11.8 million increase in asset retirement obligations in fiscal 2005 was primarily due to an upward revision in the estimated cost of plugging and abandoning wells. During fiscal 2005, the Company experienced significant increases in the cost of plugging and the salvage value of recoverable equipment associated with its wells.

The Company has no assets legally restricted for purposes of settling asset retirement obligations. Except for the item previously referenced, the Company has determined that there are no other material retirement obligations associated with tangible long-lived assets.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

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

 

     Years Ended September 30,    

Three Months Ended
December 31, 2005

   Nine Months Ended
September 30,
 
     2003     2004     2005     2004     2005    2005     2006  

Asset retirement obligations, beginning of period

   $ —       $ 3,131     $ 4,889     $ 4,889     $ 17,651    $ 5,618     $ 18,499  

Adoption of SFAS 143

     3,380       —         —         —         —        —         —    

Liabilities incurred

     93       1,725       770       650       725      120       1,616  

Liabilities settled

     (52 )     (58 )     (137 )     (4 )     —        (133 )     (180 )

Revision in estimates

     (494 )     (205 )     11,788       —         —        11,789       —    

Accretion expense

     204       296       341       83       123      257       372  
                                                       

Asset retirement obligations, end of period

   $ 3,131     $ 4,889     $ 17,651     $ 5,618     $ 18,499    $ 17,651     $ 20,307  
                                                       

The accretion expense is included in depreciation, depletion and amortization in the Company’s combined statements of income.

NOTE 5—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 AAI

The employees supporting the Company’s operations are employees of AAI. AAI provides centralized corporate functions on behalf of the Company, including legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering. The Company comprises substantially all of Atlas America’s operations, other than Atlas Pipeline, and therefore the Company bears substantially all of those costs which are reflected in general and administrative expense in the Company’s combined statements of income.

The Company participates in AAI’s cash management program. All cash activity performed by AAI on behalf of the Company, including collection of receivables, payment of payables, and the settlement of sales and purchases transactions between the Company and AAI have been recorded as parent advances and included in Advances from affiliates on the Company’s combined balance sheets.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

A reconciliation of the Company’s Advances from affiliates for the periods indicated is as follows (in thousands):

 

Balance, October 1, 2003

   $ (34,776 )

Transportation expense due to affiliates

     (1,687 )

Payment on debt to affiliate

     6,000  

Net transportation settlement

     455  
        

Balance, September 30, 2004

     (30,008 )

Transportation expense due to affiliate

     (401 )

Payment on debt to affiliate

     17,000  

Net operational settlement

     (488 )
        

Balance, September 30, 2005

     (13,897 )

Transportation expense due to affiliate

     (720 )

Payment on debt to affiliate

     8,000  

Net operational settlement

     2,360  
        

Balance, December 31, 2005

     (4,257 )

Transportation expense due to affiliate

     (4,113 )

Payment on debt to affiliate

     —    

Net operational settlement

     (1,205 )
        

Balance, September 30, 2006

   $ (9,575 )
        

All derivative activity reflected in the combined financial statements was transacted by AAI with third parties and allocated to the Company. As such, all amounts classified in the combined balance sheets as Hedge receivable are affiliate related (See Note 6).

In April 2006, AAI increased its credit facility, which is led by Wachovia Bank, N.A. (“Wachovia”), to a maximum of $200.0 million. The revolving credit facility has a current borrowing base of $150.0 million which may be redetermined subject to changes in the Company’s oil and gas reserves. Up to $50.0 million of the facility may be in the form of standby letters of credit. The facility is secured by AAI’s assets, including its subsidiaries. The Company and its subsidiaries are guarantors on the credit facility.

The Wachovia credit facility requires AAI to maintain specified ratios of current assets to current liabilities and debt to earnings before interest, taxes, depreciation, depletion and amortization (“EBITDA”). In addition, the facility limits sales, leases or transfers of assets and the incurrence of additional indebtedness and limits the dividends payable by AAI. The facility terminates in April 2011, when all outstanding borrowings must be repaid. At December 31, 2005 and September 30, 2006, $1.5 million was outstanding under this facility, including $1.5 million at each date, under letters of credit. The borrowings under this line of credit have been used to fund the Company’s investments in its investment partnerships and are included in Advances from affiliates on the Company’s combined balance sheets. The Company intends to pay to AAI all amounts outstanding under this line of credit with the proceeds of its public offering.

Relationship with Company Sponsored Investment Partnerships.    The Company conducts certain activities through, and a substantial portion of its revenues are attributable to, investment partnerships (“Partnerships”). The Company serves as managing general partner of the Partnerships and assumes customary rights and obligations for the Partnerships. As a general partner, the Company is liable for

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

Partnership liabilities and can be liable to limited partners if it breaches its responsibilities with respect to the operations of the Partnerships. The Company is entitled to receive management fees, reimbursement for administrative costs incurred, and to share in the Partnerships’ revenue, and costs and expenses according to the respective Partnership agreements.

Relationship with Atlas Pipeline.    AAI has a master gas gathering agreement with Atlas Pipeline which governs the transportation of substantially all of the natural gas the Company produces from the wells it operates. This agreement generally provides for AAI to pay Atlas Pipeline 16% of the sales price received for natural gas produced from wells located on Atlas Pipeline’s gathering systems. The Company charges rates to wells connected to these gathering systems, substantially all of which are owned by the Partnerships, generally ranging from $.35 per Mcf to 10% of the sales price received for the natural gas transported. The Company pays this amount to AAI. These fees are shown as Gathering fees—Atlas Pipeline on the Company’s combined statements of income.

Relationship with Ledgewood.    Until April 1996, Edward E. Cohen (“E. Cohen”), AAI’s Chairman of the Board, Chief Executive Officer and President, was of counsel to Ledgewood, a Philadelphia law firm. Mr. E. Cohen receives certain debt service payments from Ledgewood related to the termination of his affiliation with Ledgewood and its redemption of his interest. The Company paid Ledgewood $400, $51,300, $108,700 and $29,200 during fiscal 2003, 2004, 2005 and for the three months ended December 31, 2005, respectively, for legal services rendered to the Company.

NOTE 6—DERIVATIVE INSTRUMENTS

AAI from time to time enters into natural gas futures and option contracts on the Company’s behalf to hedge its exposure to changes in natural gas prices. At any point in time, such contracts may include regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties. NYMEX contracts are generally settled with offsetting positions, but may be settled by the delivery of natural gas.

AAI and the Company formally document all relationships between hedging instruments and the items being hedged, including the risk management objective and strategy for undertaking the hedging transactions. This includes matching the natural gas futures and options contracts to the forecasted transactions. AAI and the Company assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are highly effective in offsetting changes in the fair value of hedged items. Historically these contracts have qualified and been designated as cash flow hedges and recorded at their fair values. Derivatives are recorded on the balance sheet as assets and liabilities at fair value. Gains or losses on future contracts are determined as the difference between the contract price and a reference price, generally prices on NYMEX. For derivatives qualifying as hedges, the effective portion of changes in fair value are included in accumulated other comprehensive income (loss) and reclassified to earnings in the month the hedged gas is sold. If it is determined that a derivative is not highly effective as a hedge or it has ceased to be a highly effective hedge, due to the loss of correlation between changes in gas reference prices under a hedging instrument and actual gas prices, the Company will discontinue hedge accounting for the derivative and subsequent changes in fair value for the derivative will be recognized immediately into earnings.

At September 30, 2006, the Company had 119 open natural gas futures contracts allocated to it by AAI related to natural gas sales covering 38.1 million MMBTUs of natural gas, maturing through December 31, 2009 at a combined average settlement price of $8.85 per MMBTU. The Company

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

recognized a gain of $4.9 million on settled contracts covering natural gas production for the nine months ended September 30, 2006, which is included in gas and oil production revenues on the Company’s combined statements of income. The Company recognized no gains or losses during the nine months ended September 30, 2006 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges. The Company did not recognize any gains or losses on hedging in the nine months ended September 30, 2005. Of the $17.4 million net gain in accumulated other comprehensive income at September 30, 2006, the Company will reclassify $8.9 million of gains to its combined statements of income over the next twelve month period as these contracts expire and $8.5 million of gains will be reclassified in later periods if the fair values of the instruments remain at current market values.

At September 30, 2005, the Company had no open natural gas futures contracts allocated to it by AAI related to natural gas sales and accordingly, had no unrealized loss or gain related to open NYMEX contracts at that date. The Company recognized no gains or losses on settled contracts covering natural gas production for the years ended September 30, 2004 and 2005, respectively. The Company recognized no gains or losses during the two year period ended September 30, 2005 for hedge ineffectiveness or as a result of the discontinuance of these cash flow hedges.

As of September 30, 2006, AAI had allocated the following natural gas fixed-price swaps in place to the Company and to the Partnerships:

 

Twelve Month

Period Ending

September 30,

  

Volumes
(MMBTU)(1)

  

Average

Fixed Price
(per MMBTU)

  

Fair Value

Asset(2)
(in thousands)

2007

   10,110,000    $ 9.26    $ 20,116

2008

   14,640,000      8.75      9,945

2009

   10,950,000      8.65      7,862

2010

   2,430,000      8.61      1,650
              
   38,400,000       $ 39,573
              

(1)   MMBTU represents million British Thermal Units.
(2)   Fair value based on forward NYMEX natural gas prices, as applicable, on September 30, 2006.

The following table sets forth the book and estimated fair values of derivative instruments (in thousands):

 

     September 30, 2006  
     Book
Value
    Fair
Value
 

Assets

    

Derivative instruments

   $ 41,637     $ 41,637  
                
   $ 41,637     $ 41,637  
                

Liabilities

    

Derivative instruments

   $ (2,064 )   $ (2,064 )
                
   $ (2,064 )   $ (2,064 )
                
   $ 39,573     $ 39,573  
                

 

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ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

The fair value of the derivatives are included in the combined balance sheets as follows:

 

Unrealized hedge gains—short-term

   $ 20,116  

Other assets-long term (See note 3)

     21,521  

Unrealized hedge loss—long-term

     (2,064 )
        
   $ 39,573  
        

Of the $39.6 million net unrealized hedge gain, the Company’s retained portion of $17.4 million is included in accumulated other comprehensive income and $22.2 million has been reallocated to the Partnerships and included in the combined balance sheet as components of:

 

Other assets (see note 3)

   $ 1,156  

Accrued liabilities—short-term

     (11,265 )

Unrealized hedge loss—long-term

     (12,052 )
        
   $ (22,161 )
        

NOTE 7—COMMITMENTS AND CONTINGENCIES

The Company leases office space and equipment under leases with varying expiration dates through 2014. Rental expense was $516,000, $479,000, $1.2 million and $136,000 for the years ended September 30, 2003, 2004, 2005 and three months ended December 31, 2005, respectively. Future minimum rental commitments for the next five annual periods ending September 30, 2006 are as follows (in thousands):

 

2007

   $ 585

2008

     572

2009

     353

2010

     204

2011

     122

The Company is the managing general partner of the 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 Partnerships have the right to present their interests for purchase by the Company, as managing general partner. The Company 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.

AAI may be required to subordinate a part of its net partnership revenues from the Partnerships to the receipt by investor partners of cash distributions from the investment partnerships equal to at least 10% of their subscriptions determined on a cumulative basis, in accordance with the terms of the partnership agreements.

AAI 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.

AAI is 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

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

individuals, who leased property to AAI. The complaint alleged that AAI is not paying lessors the proper amount of royalty revenues with respect to the natural gas produced from the leased properties. In October 2006 AAI reached a tentative settlement of this lawsuit, the settlement terms are subject to final approval by the court. Pursuant to the tentative settlement terms, AAI has agreed to pay $300,000, upgrade certain gathering systems and cap certain transportation expenses chargeable to the land owners.

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

NOTE 8—LONG-TERM DEBT

Total debt consists of the following on the dates indicated (in thousands):

 

    

At September 30,

2004

   

At September 30,

2005

   

At December 31,

2005

    At September 30,
2006
 

Loans secured by vehicles

   $ 420     $ 81     $ 156     $ 90  

Less current maturities

     (339 )     (59 )     (88 )     (52 )
                                

Long-term debt

   $ 81     $ 22     $ 68     $ 38  
                                

Maturities of long-term debt are as follows:

 

Years ended September 30,      

2007

   $ 52

2008

     32

2009

     6
      
   $ 90
      

NOTE 9—OPERATING SEGMENT INFORMATION

The Company’s operations include two reportable operating segments. These operating segments reflect the way the Company manages its operations and makes business decisions. Operating segment data for the periods indicated are as follows (in thousands):

 

    Years ended September 30,  

Three Months Ended
December 31,

 

Nine Months Ended

September 30,

    2003   2004   2005       2004           2005       2005   2006

Gas and oil production

             

Revenues

  $ 38,639   $ 48,526   $ 63,499   $ 14,659   $ 24,086   $ 48,840   $ 66,696

Costs and expenses

    8,486     8,838     9,070     1,802     2,458     7,268     12,506
                                         

Segment profit

  $ 30,153   $ 39,688   $ 54,429   $ 12,857   $ 21,628   $ 41,572   $ 54,190
                                         

Partnership management

             

Revenues

  $ 69,502   $ 107,897   $ 157,839   $ 36,120   $ 49,077   $ 121,720   $ 160,216

Costs and expenses

    64,348     97,188     143,964     33,066     46,103     110,899     146,095
                                         

Segment profit

  $ 5,154   $ 10,709   $ 13,875   $ 3,054   $ 2,974   $ 10,821   $ 14,121
                                         

 

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ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

    Years Ended
September 30,
   

Three Months
Ended
December 31,

    Nine Months
Ended
September 30,
 
    2003     2004     2005     2004     2005     2005     2006  

Reconciliation of segment profit to net income

             

Segment profit

             

Gas and oil production

  $ 30,153     $ 39,688     $ 54,429     $ 12,857     $ 21,628     $ 41,572     $ 54,190  

Partnership management

    5,154       10,709       13,875       3,054       2,974       10,821       14,121  
                                                       

Total segment profit

    35,307       50,397       68,304       15,911       24,602       52,393       68,311  

General and administrative

    (8,390 )     (10,159 )     (12,297 )     (2,147 )     (5,801 )     (10,151 )     (15,387 )

Compensation reimbursement-affiliate

    (1,400 )     (1,050 )     (602 )     (213 )     (163 )     (389 )     (1,041 )

Depreciation, depletion and amortization

    (9,938 )     (12,064 )     (14,061 )     (3,165 )     (4,916 )     (10,895 )     (16,311 )

Other income—net

    358       444       79       2       57       77       962  
                                                       

Net Income

  $ 15,937     $ 27,568     $ 41,423     $ 10,388     $ 13,779     $ 31,035     $ 36,534  
                                                       

Capital expenditures

             

Gas and oil production

  $ 21,334     $ 32,172     $ 57,894     $ 11,276     $ 16,610      

Partnership management

    1,063       599       747       199       445      

Corporate

    210       481       483       170       132      
                                           
  $ 22,607     $ 33,252     $ 59,124     $ 11,645     $ 17,187      
                                           

Balance sheets

             

Goodwill

             

Gas and oil production

  $ 21,527     $ 21,527     $ 21,527     $ 21,527     $ 21,527     $ 21,527     $ 21,527  

Partnership management

    13,639       13,639       13,639       13,639       13,639       13,639       13,639  
                                                       
  $ 35,166     $ 35,166     $ 35,166     $ 35,166     $ 35,166     $ 35,166     $ 35,166  
                                                       

Total Assets

             

Gas and oil production

  $ 166,212     $ 168,715     $ 233,855     $ 186,314     $ 254,831     $ 233,855     $ 304,998  

Partnership management

    9,435       28,563       27,115       22,430       37,050       27,115       51,358  

Corporate

    2,804       1,176       9,432       12,552       23,172       9,432       60,061  
                                                       
  $ 178,451     $ 198,454     $ 270,402     $ 221,296     $ 315,053     $ 270,402     $ 416,417  
                                                       

Operating profit (loss) per segment represents total revenues less costs and expenses attributable thereto, including interest and provision for possible losses excluding general corporate expenses and depreciation, depletion and amortization.

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

For the twelve months ended September 30, 2006, and the years ended September 30, 2004 and 2005, gas sales to Hess Corporation (formerly FirstEnergy Solutions Corp.) accounted for 10%, 18% and 13%, respectively, of total revenues. No other operating segments had revenues from a single customer which exceeded 10% of total revenues.

NOTE 10—SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)

Results of operations from oil and gas producing activities:

 

     Years Ended September 30,     Three Months
Ended
December 31,
2005
 
      2003     2004     2005    
     (in thousands)  

Revenues

   $ 38,639     $ 48,526     $ 63,499     $ 24,086  

Production costs

     (6,771 )     (7,289 )     (8,166 )     (2,441 )

Exploration expenses

     (1,715 )     (1,549 )     (904 )     (17 )

Depreciation, depletion and amortization

     (8,042 )     (10,319 )     (12,288 )     (4,477 )
                                

Results of operations from oil and gas producing activities

   $ 22,111     $ 29,369     $ 42,141     $ 17,151  
                                

Capitalized Costs Related to Oil and Gas Producing Activities.    The components of capitalized costs related to the Company’s oil and gas producing activities are as follows:

 

     At September 30,     At
December 31,
2005
 
      2003     2004     2005    
     (in thousands)  

Mineral interests:

        

Proved properties

   $ 844     $ 2,544     $ 2,852     $ 2,308  

Unproved properties

     563       1,002       1,002       1,002  

Wells and related equipment

     150,657       184,046       255,828       273,804  

Support equipment

     2,185       2,890       3,644       4,173  

Uncompleted well equipment and facilities

     51       1       51       51  
                                
     154,300       190,483       263,377       281,338  

Accumulated depreciation, depletion and amortization

     (43,292 )     (54,087 )     (66,537 )     (71,059 )
                                

Net capitalized costs

   $ 111,008     $ 136,396     $ 196,840     $ 210,279  
                                

Costs Incurred in Oil and Gas Producing Activities.    The costs incurred by the Company in its oil and gas activities during fiscal years 2003, 2004 and 2005 and three months ended December 31, 2005 are as follows:

 

     At September 30,    At
December 31,
2005
      2003    2004    2005   
     (in thousands)

Property acquisition costs:

           

Proved properties

   $ 412    $ 1,700    $ 308    $ —  

Unproved properties

     —        439      —        —  

Exploration costs

     1,715      1,549      904      1,312

Development costs

     28,007      39,978      72,308      17,302
                           
   $ 30,134    $ 43,666    $ 73,520    $ 18,614
                           

 

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NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

The development costs above for the years ended September 30, 2003, 2004 and 2005 and three months ended December 31, 2005 were substantially all incurred for the development of proved undeveloped properties.

Oil and Gas Reserve Information (Unaudited).    The estimates of the Company’s proved and unproved gas and oil reserves are based upon evaluations made by management and verified by Wright & Company, Inc., an independent petroleum engineering firm, as of September 30, 2003, 2004 and 2005 and December 31, 2005. All reserves are located within the United States. Reserves are estimated in accordance with guidelines established by the Securities and Exchange Commission and the Financial Accounting Standards Board which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost escalation except by contractual arrangements.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas 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 and natural gas, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics or economic factors; (c) crude oil and natural gas, that may occur in undrilled prospects; and (d) crude oil and natural gas, and NGLs, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operation methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

There are numerous uncertainties inherent in estimating quantities of proven reserves and in projecting future net revenues and the timing of development expenditures. The reserve data presented represents estimates only and should not be construed as being exact. In addition, the standardized measure of discounted future net cash flows may not represent the fair market value of the Company’s oil and gas

 

F-33


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

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:

 

      Gas
(Mcf)
    Oil
(Bbls)
 

Balance September 30, 2002

   123,221,743     1,877,667  

Extensions and discoveries

   27,440,261     44,868  

Sales of reserves in-place

   (56,480 )   (14,463 )

Purchase of reserves in-place

   986,463     18,998  

Transfers to limited partnerships

   (8,669,521 )   (31,386 )

Revisions

   (2,662,812 )   119,038  

Production

   (6,966,899 )   (160,048 )
            

Balance September 30, 2003

   133,292,755     1,854,674  

Extensions and discoveries

   28,761,902     245,509  

Sales of reserves in-place

   (3,439 )   (1,669 )

Purchase of reserves in-place

   232,429     4,000  

Transfers to limited partnerships

   (10,132,616 )   (29,394 )

Revisions

   (2,732,385 )   382,613  

Production

   (7,285,281 )   (181,021 )
            

Balance September 30, 2004

   142,133,365     2,274,712  

Extensions and discoveries

   33,364,097     95,552  

Sales of reserves in-place

   (226,237 )   (1,010 )

Purchase of reserves in-place

   116,934     575  

Transfers to limited partnerships

   (7,104,731 )   (148,899 )

Revisions

   (2,631,044 )   196,263  

Production

   (7,625,695 )   (157,904 )
            

Balance September 30, 2005

   158,026,689     2,259,289  

Extensions and discoveries

   8,357,940     36,931  

Sales of reserves in-place

   (59,873 )   —    

Purchases of reserves in-place

   6,132     16  

Transfers to limited partnerships

   (4,740,605 )   —    

Revisions

   (1,690,863 )   653  

Production

   (1,975,070 )   (39,678 )
            

Balance December 31, 2005

   157,924,350     2,257,211  
            

Proved developed reserves at:

    

September 30, 2003

   87,760,113     1,825,280  

September 30, 2004

   95,788,656     2,125,813  

September 30, 2005

   104,786,047     2,116,412  

December 31, 2005

   108,674,675     2,122,568  

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 fiscal year-end prices, adjusted only for fixed and determinable increases in natural gas and oil prices provided by contractual

 

F-34


Table of Contents

ATLAS AMERICA E & P OPERATIONS


NOTES TO COMBINED FINANCIAL STATEMENTS — (CONTINUED)

 

agreements. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on fiscal 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 September 30, 2003, 2004 and 2005 and December 31, 2005 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.

 

    Years Ended September 30,    

Three Months
Ended
December 31,

2005

 
    2003     2004     2005    
    (in thousands)  

Future cash inflows

  $ 715,539     $ 1,096,047     $ 2,503,644     $ 1,874,432  

Future production costs

    (185,442 )     (227,738 )     (296,015 )     (290,600 )

Future development costs

    (72,476 )     (92,079 )     (117,256 )     (107,784 )

Future income tax expense

    (125,556 )     (227,862 )     (607,624 )     (445,004 )
                               

Future net cash flows

    332,065       548,368       1,482,749       1,031,044  

Less 10% annual discount for estimated timing of cash flows

    (187,714 )     (315,370 )     (876,052 )     (601,772 )
                               

Standardized measure of discounted future net cash flows

  $ 144,351     $ 232,998     $ 606,697     $ 429,272  
                               

The future cash flows estimated to be spent to develop proved undeveloped properties in the years ended September 30, 2006, 2007 and 2008 are $45.0 million, $46.0 million and $26.0 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:

 

    Years Ended September 30,    

Three Months
Ended
December 31,

2005

 
    2003     2004     2005    
    (in thousands)  

Balance, beginning of period

  $ 104,126     $ 144,351     $ 232,998     $ 606,697  

Increase (decrease) in discounted future net cash flows:

       

Sales and transfers of oil and gas, net of related costs

    (31,869 )     (41,237 )     (55,333 )     (21,645 )

Net changes in prices and production costs

    44,232       97,161       417,798       (245,838 )

Revisions of previous quantity estimates

    (229 )     6,265       (6,073 )     (4,571 )

Development costs incurred

    3,689       4,838       4,224       2,727  

Changes in future development costs

    (166 )     (1,033 )     (1,577 )     (1,159 )

Transfers to limited partnerships

    (3,313 )     (9,499 )     (24,750 )     (8,563 )

Extensions, discoveries, and improved recovery less related costs

    24,272       54,979       154,215       22,597  

Purchases of reserves in-place

    1,730       594       596       24  

Sales of reserves in-place, net of tax effect

    (200 )     (33 )     (672 )     (243 )

Accretion of discount

    13,247       19,142       32,038       21,141  

Net changes in future income taxes

    (18,749 )     (40,504 )     (151,882 )     71,614  

Estimated settlement of asset retirement obligations

    (3,131 )     (1,757 )     (12,763 )     (848 )

Estimated proceeds on disposals of well equipment

    3,380       2,055       12,740       998  

Other

    7,332       (2,324 )     5,138       (13,659 )
                               

Balance, end of period

  $ 144,351     $ 232,998     $ 606,697     $ 429,272  
                               

 

F-35


Table of Contents

 

Report of Independent Registered Public Accounting Firm

To the Owner of Atlas Energy Resources, LLC

We have audited the accompanying balance sheet of Atlas Energy Resources, LLC (the “Company”) as of July 14, 2006. This financial statement is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

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

In our opinion, the balance sheet referred to above presents fairly, in all material respects, the financial position of the Company at July 14, 2006, in conformity with accounting principles generally accepted in the United States of America.

/s/ Grant Thornton LLP

Cleveland, Ohio

July 14, 2006

 

F-36


Table of Contents

ATLAS ENERGY RESOURCES, LLC


 

BALANCE SHEETS

 

     July 14,
2006
   September 30,
2006
          (unaudited)
ASSETS   

Current assets:

     

Cash

   $ 1,000    $ 1,000
             

Total assets

   $ 1,000    $ 1,000
             

MEMBER’S EQUITY

     

Member’s equity

   $ 1,000    $ 1,000
             

Total member’s equity

   $ 1,000    $ 1,000
             

 

 

 

See accompanying note to balance sheet

 

F-37


Table of Contents

ATLAS ENERGY RESOURCES, LLC


 

NOTE TO BALANCE SHEETS

1.    Nature of Operations

Atlas Energy Resources, LLC (the “Company”) is a Delaware limited liability company formed in June 2006 to acquire various subsidiaries of Atlas America, Inc.

The Company intends to offer 6,325,000 common units, representing limited liability interests, pursuant to a public offering and to concurrently issue 30,299,365 common units, representing additional limited liability company interests, to Atlas America, Inc., 50,000 common units to the Company’s president and chief operating officer and 748,456 Class A units, representing a 2% interest in the Company, to Atlas Energy Management, Inc.

Atlas America, Inc. contributed $1,000 as the organizational member on July 14, 2006. There have been no other transactions involving the Company as of September 30, 2006.

 

F-38


Table of Contents

 

Appendix A

AMENDED AND RESTATED

OPERATING AGREEMENT

OF

ATLAS ENERGY RESOURCES, LLC

 



Table of Contents

 

TABLE OF CONTENTS

 

            Page No.

Article 1

  

DEFINITIONS

   A-1

Section 1.1

  

Definitions

   A-1

Section 1.2

  

Construction

   A-19

Article 2

  

ORGANIZATION

   A-19

Section 2.1

  

Formation

   A-19

Section 2.2

  

Name

   A-19

Section 2.3

  

Registered Office; Registered Agent; Principal Office; Other Offices

   A-20

Section 2.4

  

Purposes and Business

   A-20

Section 2.5

  

Powers

   A-20

Section 2.6

  

Power of Attorney

   A-20

Section 2.7

  

Term

   A-22

Section 2.8

  

Title to Company Assets

   A-22

Article 3

  

RIGHTS OF MEMBERS

   A-22

Section 3.1

  

Limitation of Liability

   A-22

Section 3.2

  

Members

   A-22

Section 3.3

  

Management of Business

   A-23

Section 3.4

  

Outside Activities of the Members

   A-23

Section 3.5

  

Member Interests

   A-23

Section 3.6

  

Respective Voting Rights of Classes of Units and Interests

   A-24

Section 3.7

  

Conversion of Class A and Management Incentive Interests

   A-24

Section 3.8

  

Rights of Members

   A-25

Article 4

   CERTIFICATES; RECORD HOLDERS; TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS    A-25

Section 4.1

  

Certificates

   A-25

Section 4.2

  

Mutilated, Destroyed, Lost or Stolen Certificates

   A-26

Section 4.3

  

Record Holders

   A-26

Section 4.4

  

Transfer Generally

   A-27

Section 4.5

  

Registration and Transfer of Member Interests

   A-27

Section 4.6

  

Restrictions on Transfers

   A-28

Section 4.7

  

Citizenship Certificates; Non-citizen Assignees

   A-28

Section 4.8

  

Redemption of Member Interests of Non-citizen Assignees

   A-29

Article 5

  

CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS

   A-30

Section 5.1

  

Redemption or Exchange of the Pre-IPO Member Interests

   A-30

Section 5.2

  

Contributions by the Underwriters

   A-30

Section 5.3

  

Interest and Withdrawal

   A-31

Section 5.4

  

Capital Accounts

   A-31

Section 5.5

  

Issuances of Additional Company Securities

   A-33

Section 5.6

  

Limitations on Issuance of Additional Company Securities

   A-34

Section 5.7

  

No Preemptive Rights

   A-34

Section 5.8

  

Splits and Combinations

   A-34

Section 5.9

  

Fully Paid and Non-Assessable Nature of Member Interests

   A-35

Section 5.10

  

Registration Rights of Atlas America and its Affiliates

   A-35

Article 6

  

ALLOCATIONS AND DISTRIBUTIONS

   A-37

Section 6.1

  

Allocations for Capital Account Purposes

   A-37

Section 6.2

  

Allocations for Tax Purposes

   A-42

 

A-i


Table of Contents

 

          Page No.

Section 6.3

  

Requirement and Characterization of Distributions; Distributions to Record Holders

   A-44

Section 6.4

  

Distributions of Available Cash from Operating Surplus

   A-45

Section 6.5

  

Payment of the EP MID

   A-45

Section 6.6

  

Distributions of Available Cash from Capital Surplus

   A-46

Section 6.7

  

Adjustment of Initial Quarterly Distribution, First Target Distribution, Second Target Distribution and Unrecovered Capital

   A-46

Section 6.8

  

Entity-Level Taxation

   A-46

Article 7

  

MANAGEMENT AND OPERATION OF BUSINESS

   A-47

Section 7.1

  

Board of Directors

   A-47

Section 7.2

  

Certificate of Formation

   A-50

Section 7.3

  

Restrictions on the Board of Directors’ Authority

   A-51

Section 7.4

  

Officers

   A-51

Section 7.5

  

Outside Activities

   A-53

Section 7.6

  

Loans or Contributions from the Company or Group Members

   A-53

Section 7.7

  

Indemnification

   A-53

Section 7.8

  

Exculpation of Liability of Indemnitees

   A-56

Section 7.9

  

Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties

   A-57

Section 7.10

  

Duties of Officers and Directors

   A-58

Section 7.11

  

Purchase or Sale of Company Securities

   A-58

Section 7.12

  

Reliance by Third Parties

   A-58

Article 8

  

BOOKS, RECORDS, ACCOUNTING AND REPORTS

   A-59

Section 8.1

  

Records and Accounting

   A-59

Section 8.2

  

Fiscal Year

   A-59

Section 8.3

  

Reports

   A-59

Article 9

  

TAX MATTERS

   A-60

Section 9.1

  

Returns and Information

   A-60

Section 9.2

  

Tax Elections

   A-60

Section 9.3

  

Tax Controversies

   A-60

Section 9.4

  

Withholding

   A-60

Article 10

  

DISSOLUTION AND LIQUIDATION

   A-61

Section 10.1

  

Dissolution

   A-61

Section 10.2

  

Liquidator

   A-61

Section 10.3

  

Liquidation

   A-61

Section 10.4

  

Cancellation of Certificate of Formation

   A-62

Section 10.5

  

Return of Contributions

   A-62

Section 10.6

  

Waiver of Partition

   A-62

Section 10.7

  

Capital Account Restoration

   A-62

Article 11

   AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE    A-63

Section 11.1

  

Amendment of Operating Agreement

   A-63

Section 11.2

  

Amendment Requirements

   A-64

Section 11.3

  

Unitholder Meetings

   A-65

Section 11.4

  

Notice of Meetings of Members

   A-66

Section 11.5

  

Record Date

   A-66

A-ii


Table of Contents

 

          Page No.

Section 11.6

  

Adjournment

   A-67

Section 11.7

  

Waiver of Notice; Approval of Meeting

   A-67

Section 11.8

  

Quorum; Required Vote for Member Action; Voting for Directors

   A-67

Section 11.9

  

Conduct of a Meeting; Member Lists

   A-68

Section 11.10

  

Voting and Other Rights

   A-68

Section 11.11

  

Proxies and Voting

   A-68

Section 11.12

  

Notice of Member Business and Nominations

   A-69

Article 12

  

MERGER, CONSOLIDATION OR CONVERSION

   A-70

Section 12.1

  

Authority

   A-70

Section 12.2

  

Procedure for Merger, Consolidation or Conversion

   A-70

Section 12.3

  

Approval by Members of Merger, Consolidation or Conversion

   A-72

Section 12.4

  

Certificate of Merger; Certificate of Conversion

   A-73

Section 12.5

  

Effect of Merger or Conversion

   A-73

Section 12.6

  

Business Combination Limitations

   A-74

Article 13

  

RIGHT TO ACQUIRE MEMBER INTERESTS

   A-74

Section 13.1

  

Right to Acquire Member Interests

   A-74

Article 14

  

GENERAL PROVISIONS

   A-75

Section 14.1

  

Addresses and Notices

   A-75

Section 14.2

  

Further Action

   A-76

Section 14.3

  

Binding Effect

   A-76

Section 14.4

  

Integration

   A-76

Section 14.5

  

Creditors

   A-76

Section 14.6

  

Waiver

   A-76

Section 14.7

  

Counterparts

   A-76

Section 14.8

  

Applicable Law

   A-76

Section 14.9

  

Invalidity of Provisions

   A-77

Section 14.10

  

Consent of Members

   A-77

Exhibit A: Form of Common Unit Certificate

   A-1

 

A-iii


Table of Contents

 

This AMENDED AND RESTATED OPERATING AGREEMENT OF ATLAS ENERGY RESOURCES LLC, dated as of             , 2006 is entered into by and among Atlas America, Inc. (“Atlas America”), together with any other Persons who hereafter become Members in Atlas Energy Resources, LLC or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

Article 1

DEFINITIONS

Section 1.1    Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

12-Quarter Test” requires that, for each Quarter in the Incentive Trigger Period:

 

(a)   the Company distributes Available Cash from Operating Surplus to holders of the Outstanding Class A Units and Common Units in an amount that on average exceeds the First Target Distribution on all of the Outstanding Class A Units and Common Units over the Incentive Trigger Period;

 

(b)   the Company generates Adjusted Operating Surplus in an amount that, on average, equals or exceeds 100% of all distributions of Available Cash to the Outstanding Class A Units and Common Units up to the First Target Distribution on all of the Outstanding Class A Units and Common Units, plus 117.65% of any distributions to the Outstanding Class A Units and Common Units in excess of the First Target Distribution up to the Second Target Distribution and 133.33% of any distributions to the Outstanding Class A Units and Common Units in excess of the Second Target Distribution; and

 

(c)   the Company does not reduce the amount of Available Cash distributed per Outstanding Class A Unit or Common Unit in respect of any such Quarter in the Incentive Trigger Period.

4-Quarter Test” requires that, for each of (i) the last four full, consecutive, non-overlapping calendar Quarters in the Incentive Trigger Period, (ii) any four full consecutive, non-overlapping Quarters occurring after such last four Quarters in the Incentive Trigger Period, provided that the Company has distributed Available Cash from Operating Surplus to the holders of the Outstanding Class A Units and Common Units in an amount that equals or exceeds the Initial Quarterly Distribution for each Quarter occurring between the end of the Incentive Trigger Period and the beginning of the four full, consecutive, non-overlapping Quarters that satisfy the 4-Quarter Test, or (iii) any four full, consecutive, non-overlapping Quarters occurring partially within and partially after such last four Quarters of the Incentive Trigger Period:

 

(a)   the Company distributes Available Cash from Operating Surplus to the holders of Outstanding Class A Units and Common Units in an amount that exceeds the First Target Distribution on all of the Outstanding Class A Units and Common Units;

 

(b)   the Company generates Adjusted Operating Surplus in an amount that equals or exceeds 100% of all distributions of Available Cash to the Outstanding Class A Units and Common Units up to the First Target Distribution, plus 117.65% of any distributions to the Outstanding Class A Units and Common Units in excess of the First Target Distribution up to the Second Target Distribution and 133.33% of any distributions to the Outstanding Class A Units and Common Units in excess of the Second Target Distribution; and

 

(c)   the Company does not reduce the amount of Available Cash distributed per Outstanding Class A Unit or Common Unit in respect of any of such four Quarters.

 

A-1


Table of Contents

 

Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing the asset base of the Company Group from the asset base of the Company Group existing immediately prior to such transaction; provided however, that any acquisition of properties or assets of another Person that is made solely for investment purposes shall not constitute an Acquisition under this Agreement.

Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

 

(a)   Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

 

(b)   If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided that the amount treated as Additional Book Basis as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceed the remaining Additional Book Basis attributable to all of the Company’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Company’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess Additional Book Basis bears to the Additional Book Basis as of the beginning of such period.

Additional Member” means a Person admitted as a Member of the Company pursuant to Section 5.5 and who is shown as such on the books and records of the Company.

Adjusted Capital Account” means the Capital Account maintained for each Member as of the end of each fiscal year of the Company, (a) increased by any amounts that such Member is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all deductions in respect of depletion that, as of the end of such fiscal year are expected to be made to such Member’s Capital Account in respect of the oil and gas properties of the Company, (ii) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Member in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (iii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Member in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Member’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii)). The foregoing definition of


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Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Member in respect of a Common Unit, a Class A Unit, a Management Incentive Interest or any other Member Interest shall be the amount that such Adjusted Capital Account would be if such Common Unit, Class A Unit, Management Incentive Interest or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Common Unit, Class A Unit, Management Incentive Interest or other Member Interest was first issued.

Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to that period; less (b) any net increase in Working Capital Borrowings with respect to that period; less (c) any net reduction in cash reserves for Operating Expenditures with respect to that period not relating to an Operating Expenditure made with respect to that period; plus (d) any net decrease in Working Capital Borrowings with respect to that period; plus (e) any net increase in cash reserves for Operating Expenditures made with respect to that period required by any debt instrument for the repayment of principal, interest or premium. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus.

Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.4(c)(i) or Section 5.4(c)(ii).

Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all Members.

Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution as determined by the Board of Directors. The Board of Directors shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Contributed Properties contributed to the Company in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each Contributed Property.

Agreement” means this Amended and Restated Operating Agreement of Atlas Energy Resources, LLC, as it may be amended, supplemented or restated from time to time.

APL Omnibus Agreement Amendment” means the Amendment and Joinder to Omnibus Agreement of even date herewith among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Resource Energy, LLC, Viking Resources, LLC, the Company and Atlas Energy Operating Company, LLC.

Assignee” means a Non-citizen Assignee or a Person to whom one or more Member Interests have been transferred in a manner permitted under this Agreement, but who has not been admitted as a Substituted Member.


 

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Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a manager, director, officer or partner or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

Atlas America” means Atlas America, Inc., a Delaware corporation.

Atlas Energy Management” means Atlas Energy Management, Inc., a Delaware corporation.

Audit Committee” means a committee of the Board of Directors composed entirely of two or more Independent Directors.

Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

 

(a)   the sum of:

 

 

  (i)   all cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of that Quarter; and

 

  (ii)   all additional cash and cash equivalents of the Company Group (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash for that Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter,

 

(b)   less the amount of any cash reserves established by the Board of Directors (or the Company’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) to

 

  (i)   provide for the proper conduct of the business of the Company Group (including reserves for future capital expenditures and for anticipated future credit needs of the Company Group);

 

  (ii)   comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject; or

 

  (iii)   provide funds for distributions pursuant to Section 6.3(a), Section 6.4 and Section 6.5 with respect to any one or more of the next four Quarters;

provided, however, that the Board of Directors may not establish cash reserves pursuant to clause (iii) above if the effect of such reserves would be that the Company is unable to distribute the Initial Quarterly Distribution on all Common Units and Class A Units with respect to such Quarter; and provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of that Quarter but on or before the date of determination of Available Cash for that Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within that Quarter if the Board of Directors so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

Board of Directors” has the meaning assigned to such term in Section 7.1(a).


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Book Basis Derivative Items” means any item of income, deduction, gain, loss, Simulated Depletion, Simulated Gain or Simulated Loss included in the determination of Net Income or Net Loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, Simulated Depletion, or gain, loss, Simulated Gain or Simulated Loss with respect to an Adjusted Property).

Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Members pursuant to Section 5.4(c).

Book-Tax Disparity” means, with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Member’s share of the Company’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Member’s Capital Account balance as maintained pursuant to Section 5.4 and the hypothetical balance of such Member’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Members pursuant to Section 5.4(c).

Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America shall not be regarded as a Business Day.

Capital Account” means the capital account maintained for a Member pursuant to Section 5.4. The Capital Account of a Member in respect of a Unit or any other Member Interest shall be the amount that such Capital Account would be if such Unit or other Member Interest were the only interest in the Company held by such Member from and after the date on which such Unit or other Member Interest was first issued.

Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Member contributes to the Company.

Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new or the improvement of existing, capital assets (including undeveloped leasehold acreage, properties containing estimated proved reserves (whether or not producing) and other similar assets) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has an equity interest that is made by such Group Member to fund the Group Member’s pro rata share of the cost of the acquisition of existing, or the construction of new or the improvement of existing, capital assets, in each case if such addition, improvement, acquisition or construction is made to increase the asset base of the Company Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from asset base of the Company Group or such Person, as the case may be, immediately prior to such addition, improvement, acquisition or construction; provided, however, that any such addition, improvement, acquisition or construction that is made solely for investment purposes shall not constitute a Capital Improvement under this Agreement.

Capital Surplus” has the meaning assigned to such term in Section 6.3(a).

Carrying Value” means (a) with respect to a Contributed Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, depletion (including Simulated Depletion), amortization and cost recovery deductions charged to the Members’ Capital Accounts in respect of such Contributed Property, and (b) with respect to any other Company property, the adjusted basis of such property for

 


 

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federal income tax purposes, all as of the time of determination. The Carrying Value of any property shall be adjusted from time to time in accordance with Section 5.4(c)(i) and Section 5.4(c)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Company properties, as deemed appropriate by the Board of Directors.

Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more Units or (b) a certificate, in such form as may be adopted by the Board of Directors, issued by the Company evidencing ownership of one or more other Company Securities.

Certificate of Formation” means the Certificate of Formation of the Company filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Formation may be amended, supplemented or restated from time to time.

Citizenship Certification” means a properly completed certificate in such form as may be specified by the Board of Directors by which an Assignee or a Member certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Citizen.

Class A Member Interests” means the Member Interests represented by the Class A Units.

Class A Unit” means a Unit representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Class A Units in this Agreement.

Class A Unit Majority” means at least a majority of the Outstanding Class A Units, voting together as a single class separate from the Common Units and any other Member Interest or Company Securities.

Class B Member Interests” means the Member Interests represented by the Common Units.

Class C Member Interests” means the Member Interests represented by the Management Incentive Interests.

Closing Date” means the first date on which Common Units are sold by the Company to the Underwriters pursuant to the provisions of the Underwriting Agreement.

Closing Price” for any day means the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted for trading on the principal National Securities Exchange on which such Member Interests of such class are listed or admitted to trading or, if such Member Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the Nasdaq National Market or any other system then in use, or, if on any such day such Member Interests are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Member Interests of such class selected by the Board of Directors, or if on any such day no market maker is making a market in such Member Interests of such class, the fair value of such Member Interests on such day as determined by the Board of Directors.


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Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

Commences Commercial Service” and “Commenced of Commercial Service” shall mean the date a Capital Improvement or replacement asset is first put into commercial service following completion of construction and testing.

Commission” means the United States Securities and Exchange Commission.

Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor, collar or other similar agreement or arrangement, each of which is for the purpose of hedging the exposure of the Company Group to fluctuations in the price of hydrocarbons in their operations and not for speculative purposes.

Common Unit” means a Unit representing a fractional part of the Member Interests of all Members and, to the extent they are treated as Members hereunder, Assignees, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not include a Class A Unit prior to its conversion into a Common Unit pursuant to this Agreement. As specified in Section 3.5(b), the Class B Member Interests constitute the Common Units.

Common Unit Majority” means at least a majority of the Outstanding Common Units, voting together as a single class separate from the Class A Units and any other Member Interests or Company Securities.

Company” means Atlas Energy Resources, LLC, a Delaware limited liability company, and any successors thereto.

Company Group” means the Company and each Subsidiary of the Company, treated as a single consolidated entity.

Company Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Section 1.704-2(d).

Company Security” means any class or series of equity interest in the Company (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Company), including the Units and the Management Incentive Interests.

Conflicts Committee” means a committee of the Board of Directors composed entirely of two or more Directors who are not (a) Officers or employees of the Company or any Subsidiary of the Company, (b) managers, directors, officers or employees of any Affiliate of the Company or (c) holders of any ownership interest in the Company Group other than Common Units, and who also meet the independence standards established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed for trading, which standards are applicable to members of audit committees of boards of directors.

Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Company. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.4(c), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

Contribution Agreement” means the Contribution and Assumption Agreement of even date herewith among Atlas America, the Company and Atlas Energy Operating Company, LLC.


 

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Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(x).

Current Market Price” means, in respect of any class of Member Interests, as of the date of determination, the average of the daily Closing Prices per Member Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

Delaware Act” means the Delaware Limited Liability Company Act, 6 Del. C. Section 18-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

DGCL” means the General Corporation Law of the State of Delaware, 8 Del. C. Section 101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

Director” means a member of the Board of Directors.

Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

Eligible Citizen” means a Person qualified to own interests in real property in jurisdictions in which any Group Member does business or proposes to do business from time to time, and whose status as a Member or Assignee does not or would not subject such Group Member to a significant risk of cancellation or forfeiture of any of its properties or any interest therein.

EP MID” means a one-time Management Incentive Distribution paid to the Management Incentive Interests equal to (a) 17.65% of the sum of any amounts by which distributions of Available Cash from Operating Surplus per Common Unit and Class A Unit during the Incentive Trigger Period equaled or exceeded the First Target Distribution up to the Second Target Distribution and (b) 33.33% of the sum of any amounts by which the Company’s cash distributions per Common Unit and Class A Unit during the Incentive Trigger Period equaled or exceeded the Second Target Distribution.

Estimated Incremental Quarterly Tax Amount” has the meaning assigned to such term in Section 6.8.

Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors (including a majority of the Conflicts Committee) of the average quarterly Maintenance Capital Expenditures that the Company will need to incur over the long term to maintain the asset base of the Company Group existing at the time the estimate is made. The Board of Directors (including a majority of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future Estimated Maintenance Capital Expenditures. The Company shall disclose to its Members any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements. Expansion Capital Expenditures shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction of a Capital


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Improvement and paid during the period beginning on the date that the Company enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service or the date that such Capital Improvement is abandoned or disposed of. Debt incurred or equity issued to fund such construction period interest payments or such construction period distributions on equity paid during such period shall also be deemed to be debt incurred or equity issued, as the case may be, to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the Board of Directors, including a majority of the Conflicts Committee, shall determine the allocation between the amounts paid for each.

Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time, and any successor for such statute.

Final Adjudication” has the meaning assigned to such term in Section 7.7(c).

Gas Gathering Agreements Amendment” means the Amendment and Joinder to Gas Gathering Agreements among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Resource Energy, LLC, Viking Resources, LLC, Atlas Noble, LLC, the Company and Atlas Energy Operating Company, LLC of even date herewith, as the same may be amended from time to time.

Group” means a Person that with or through any of its Affiliates or Associates has any agreement, arrangement or understanding for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to ten or more Persons), exercising investment power or disposing of any Member Interest with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Member Interests.

Group Member” means a member of the Company Group.

Group Member Agreement” means the partnership agreement of any Group Member, other than the Company, that is a limited or general partnership, the limited liability company or operating agreement of any Group Member, other than the Company, that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, including any amendments, supplements or restatements from time to time.

Holder” has the meaning assigned to such term in Section 5.10(a).

Incentive Trigger Period” means the 12 full, consecutive, non-overlapping Quarters that begin with the first Quarter in respect of which the Company distributes Available Cash from Operating Surplus to holders of the Outstanding Class A Units and Common Units in an amount that equals or exceeds the First Target Distribution. If the 12-Quarter Test and the 4-Quarter Test are not satisfied with respect to a period of 12 full, consecutive, non-overlapping calendar Quarters, the Incentive Trigger Period may begin with the first Quarter following the Quarter in which the 12-Quarter Test is not met, or, where the 12-Quarter Test is not satisfied because the Company failed clause (c) of the 12-Quarter Test, the Incentive Trigger Period may begin with the quarter in which the reduction that caused the Company to fail such clause (c) occurs.

“Incremental Income Tax has the meaning set forth in Section 6.8.


 

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Indemnified Persons” has the meaning assigned to such term in Section 5.10(c).

Indemnitee” means (a) any Person who is or was a Director, Officer, employee or agent of the Company or a Tax Matters Partner of the Company, (b) any Person who is or was a member, partner, manager, director, officer, fiduciary or trustee of any Group Member (other than the Company) or any Affiliate of a Group Member (other than the Company), (c) any Person who is or was serving at the request of the Company as a director, manager, officer, tax matters partner, fiduciary or trustee of another Person; provided that a Person shall not be an “Indemnitee” by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services and (d) any Person that the Company designates as an “Indemnitee” for purposes of this Agreement.

Independent Director” means a Director who meets the independence and other standards required of the members of the audit committee of a board of directors, which standards are established by the Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which the Common Units are listed for trading.

Initial Common Units” means the Common Units sold in the Initial Offering.

Initial Members” means Atlas America, with respect to the Common Units, the Class A Units and Management Incentive Interests received by it pursuant to Section 5.1, and the Underwriters, with respect to the Common Units issued to the Underwriters as described in Section 5.2 in connection with the Initial Offering, in each case upon being admitted to the Company in accordance with this Agreement.

Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

Initial Operating Agreement” means the Operating Agreement of Atlas Energy Resources, LLC, dated as of June 23, 2006, as amended through the date of this Agreement.

Initial Quarterly Distribution” means $0.42 per Common Unit per Quarter (or, with respect to the period commencing on the Closing Date and ending on December 31, 2006, it means the product of $0.42 multiplied by a fraction of which the numerator is the number of days in such period and of which the denominator is 92), subject to adjustment in accordance with Section 6.7 and Section 6.8.

Initial Unit Price” means (a) with respect to the Common Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Company Securities, the price per Unit at which such class or series of Company Securities is initially sold by the Company, as determined by the Board of Directors, in each case adjusted as the Board of Directors determines to be appropriate to give effect to any distribution, subdivision or combination of Company Securities.

Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters pursuant to the exercise of the Over-Allotment Option); (c) sales or other voluntary or involuntary dispositions of any assets of any


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Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) the termination of Commodity Hedge Contracts and interest rate swap agreements prior to their respective specified termination dates; (e) capital contributions received; and (f) corporate organizations and restructurings.

Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

Issue Price” means the price at which a Unit is purchased from the Company, after taking into account any sales commission or underwriting discount charged to the Company by the Underwriters.

Liquidation Date” means the date on which an event giving rise to the dissolution of the Company occurs.

Liquidator” means one or more Persons selected by the Board of Directors to perform the functions described in Section 10.2 as liquidating trustee of the Company within the meaning of the Delaware Act.

Maintenance Capital Expenditures” means cash expenditures, including expenditures for the addition or improvement to the asset base owned by any Group Member (including plugging and abandonment costs), or for the acquisition of existing, or the construction or development of new, capital assets (including replacement of equipment and oil and natural gas reserves, undeveloped leasehold acreage, properties containing estimated proved reserves and other similar assets) if such expenditure is made to maintain, including over the long term, the asset base of the Company Group. Maintenance Capital Expenditures shall not include (a) Expansion Capital Expenditures or (b) Investment Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, in each case, to finance the construction or development of a replacement asset and paid during the period beginning on the date that the Company enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset.

Management Incentive Distribution” means any distribution made to the holder of the Management Incentive Interests pursuant to Section 6.4(b)(iii)(c), Section 6.4(b)(iv)(C) or Section 6.5.

Management Incentive Interests” means the non-voting Member Interest having the rights and obligations specified with respect to Management Incentive Interests in this Agreement. As specified in Section 3.5(c), the Class C Member Interests constitute the Management Incentive Interests. The holder(s) of the Management Incentive Interests have the right to receive any Management Incentive Distributions.

Management Agreement” means the Management Agreement among the Company, Atlas Energy Operating Company, LLC and Atlas Energy Management of even date herewith, as the same may be amended from time to time.

Member” means, unless the context otherwise requires, (a) each Initial Member, Substituted Member and Additional Member or (b) solely for purposes of Articles 5, 6, 7, 9, 11 and 12, each Assignee;


 

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provided, however, that when the term “Member” is used herein in the context of any vote or approval, including in Articles 11 and 12, such term shall not, solely for such purpose, include any holder of the Management Incentive Interests (solely with respect to such Management Incentive Interests and not with respect to any other Member Interest held by such Person) except as required by law.

Member Interest” means the ownership interest of a Member or Assignee in the Company, which may be evidenced by Units, Management Incentive Interests or other Company Securities or a combination thereof or interest therein, and includes any and all benefits to which such Member or Assignee is entitled as provided in this Agreement, together with all obligations of such Member or Assignee to comply with the terms and provisions of this Agreement; provided, however, that when the term “Member Interest” is used herein in the context of any vote or approval, including Article 11 and Article 12, such term shall not, solely for such purpose, include any Management Incentive Interests except as may be required by applicable law.

“Member Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

Member Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

Member Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Member Nonrecourse Debt.

Merger Agreement” has the meaning assigned to such term in Section 12.1.

MII Vesting Period” means the period commencing with the Closing Date and ending on the last day of the Quarter as of which both the 12-Quarter Test and the 4-Quarter Test are met.

National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Exchange Act of 1934 and any successor to such statute.

Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any liabilities either assumed by the Company upon such contribution or to which such property is subject when contributed, and (b) in the case of any property distributed to a Member or Assignee by the Company, the Company’s Carrying Value of such property (as adjusted pursuant to Section 5.4(c)(ii)) at the time such property is distributed, reduced by any indebtedness either assumed by such Member or Assignee upon such distribution or to which such property is subject at the time of distribution, in either case, as determined under Section 752 of the Code.

Net Income” means, for any taxable year, the excess, if any, of the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Income shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.


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Net Loss” means, for any taxable year, the excess, if any, of the Company’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year over the Company’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable year. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses, and Simulated Depletion, but shall not include any items specially allocated under Section 6.1(d); provided that the determination of the items that have been specially allocated under Section 6.1(d) shall be made as if Section 6.1(d)(xi) were not in this Agreement.

Net Positive Adjustments” means, with respect to any Member, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Member pursuant to Book-Up Events and Book-Down Events.

Net Termination Gain” means, for any taxable year, the sum, if positive, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Gain shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

Net Termination Loss” means, for any taxable year, the sum, if negative, of all items of income, gain, loss or deduction recognized by the Company after the Liquidation Date. The items included in the determination of Net Termination Loss shall be determined in accordance with Section 5.4(b) and shall include Simulated Gains, Simulated Losses and Simulated Depletion, but shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

Non-citizen Assignee” means a Person whom the Board of Directors has determined does not constitute an Eligible Citizen, pursuant to Section 4.7.

Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Members pursuant to Section 6.2(c)(iii), Section 6.2(d)(i)(A), Section 6.2(d)(ii)(A) and Section 6.2(d)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

Nonrecourse Deductions” means any and all items of loss, deduction, expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code), Simulated Depletion or Simulated Loss that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-1(a)(2).

Notice of Election to Purchase” has the meaning assigned to such term in Section 13.1(b).

Officers” means the officers of the Company.

Omnibus Agreement” means the Omnibus Agreement between the Company and Atlas America of even date herewith, as the same may be amended from time to time.

Operating Companies” means Atlas Energy Operating Company, LLC, a Delaware limited liability company, any other operating Subsidiaries of the Company and any successors thereto.


 

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Operating Expenditures” means all Company Group expenditures (or the Company’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including taxes, amounts paid under the Management Agreement, payments made in the ordinary course of business under Commodity Hedge Contracts (excluding payments made in connection with the termination of any Commodity Hedge Contract prior to the expiration of its terms), provided that with respect to amounts paid in connection with the initial purchase or placing of a Commodity Hedge Contract, such amounts shall be amortized over the life of the applicable Commodity Hedge Contract and upon its termination, if earlier, Director and Officer compensation, compensation paid to members of the Board of Directors, repayment of Working Capital Borrowings, debt service payments, and Estimated Maintenance Capital Expenditures, subject to the following:

 

(a)   Repayment of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of Operating Surplus shall not constitute Operating Expenditures when actually repaid.

 

(b)   Payments (including prepayments) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures.

 

(c)   Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) actual Maintenance Capital Expenditures, (iii) Investment Capital Expenditures, (iv) payment of transaction expenses (which, with respect to the termination of a Commodity Hedge Contract prior to its stipulated settlement or termination date, such transaction expenses shall constitute any payments due from any Group Member upon such settlement or termination) relating to Interim Capital Transactions, (v) distributions to Members (including distributions in respect of any Management Incentive Distributions) or (vi) non-Pro Rata repurchases of Units of any class made with proceeds of a substantially concurrent equity issuance.

 

(d)   Where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the Board of Directors, including a majority of the Conflicts Committee, shall determine the allocation between the amounts paid for each and, with respect to the part of such capital expenditures made for Maintenance Capital Expenditures, the period over which such Maintenance Capital Expenditures will be included in Estimated Maintenance Capital Expenditures and deducted as an Operating Expenditure in calculating Operating Surplus.

Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

 

(a)   the sum of (i) $40.0 million, (ii) all cash receipts of the Company Group (or the Company’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, including Working Capital Borrowings but excluding cash receipts from Interim Capital Transactions (except to the extent specified in Section 6.6), (iii) all cash receipts of the Company Group (or the Company’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings and (iv) cash distributions paid on equity issued to finance all or a portion of the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset (such as equipment or reserves) during the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to occur of the date the Capital Improvement or capital asset Commences Commercial Service or the date that it is abandoned or disposed of (equity issued to fund construction period interest payments on debt incurred, or construction period distributions on equity issued, to finance the construction, acquisition or development of a Capital Improvement or

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replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or development of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)); less

 

(b)   the sum of

 

  (i)   Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period;

 

  (ii)   the amount of cash reserves established by the Board of Directors (or the Company’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to provide funds for future Operating Expenditures; and

 

  (iii)    all Working Capital Borrowings not repaid within twelve months after having been incurred;

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the Board of Directors so determines.

Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Company or any of its Affiliates) acceptable to the Board of Directors.

Option Closing Date” means the date or dates on which any Common Units are sold by the Company to the Underwriters upon exercise of the Over-Allotment Option.

Outstanding” means, with respect to Company Securities, all Company Securities that are issued by the Company and reflected as outstanding on the Company’s books and records as of the date of determination; provided, however, that (i) no Company Securities held by the Company or any other Group Member shall be considered Outstanding and (ii) if at any time any Person or Group (other than Atlas Energy Management or Atlas America or their Affiliates) beneficially owns 20% or more of any Outstanding Company Securities of any class then Outstanding, all Company Securities owned by such Person or Group shall not be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Members to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, provided that the foregoing limitation shall not apply to any Person or Group who acquired 20% or more of any Outstanding Company Securities of any class then Outstanding directly from Atlas Energy Management or Atlas America or their Affiliates with the prior approval of the Board of Directors.

Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Company pursuant to the Underwriting Agreement.

Percentage Interest” means, as of any date of determination (a) as to any Unitholder holding Class A Units, the product obtained by multiplying (i) 2% by (ii) the quotient obtained by dividing (A) the number of Class A Units held by such Unitholder by (B) the total number of Outstanding Class A Units; (b) as to any Unitholder holding Common Units, the product obtained by multiplying (i) 98% by (ii) the quotient obtained by dividing (A) the number of Common Units held by such Unitholder by (B) the total number of all Outstanding Common Units, and (c) as to the holders of other Company Securities issued by the Company in accordance with Section 5.5, the percentage established as a part of such issuance.


 

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Person” means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization or other enterprise (including an employee benefit plan), association, government agency or political subdivision thereof or other entity.

Plan of Conversion” has the meaning assigned to the term in Section 12.1.

Pre-IPO Member Interest” shall have the meaning assigned to such term in Section 3.5(a).

Prime Rate” means the prime rate of interest as quoted from time to time by the Wall Street Journal or another source reasonably selected by the Company.

Pro Rata” means (a) when modifying Units or any class thereof, apportioned equally among all such Units, in accordance with their relative Percentage Interests, (b) when modifying other Member Interests with respect to which a Percentage Interest is assigned, apportioned equally among such class of Member Interests in accordance with their Percentage Interests, (c) when modifying other Member Interests with respect to which a Percentage Interest is not assigned, apportioned among the holders of such Member Interests based upon the ratio that each Member’s share of such Member Interests bears to the total of such Member Interest, and (d) when modifying Members, apportioned among all designated Members in accordance with their relative Percentage Interest.

Purchase Date” means the date determined by the Board of Directors as the date for purchase of all Outstanding Units of a certain class pursuant to Article 13.

Quarter” means, unless the context requires otherwise, a fiscal quarter, or, with respect to the first fiscal quarter after the Closing Date, the portion of such fiscal quarter after the Closing Date, of the Company.

Recapture Income” means any gain recognized by the Company (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Company, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

Record Date” means the date established by the Company for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Members or entitled to exercise rights in respect of any lawful action of Members or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

Record Holder” means the Person in whose name a Common Unit is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or with respect to other Company Securities, the Person in whose name any such other Company Security is registered on the books that the Company has caused to be kept as of the opening of business on such Business Day.

Redeemable Interests” means any Member Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.8.

Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-134995) as it has been or as it may be amended or supplemented from time to time, filed by the Company with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.


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Remaining Net Positive Adjustments” means as of the end of any taxable period, with respect to the Unitholders, the excess of (i) the Net Positive Adjustments of the Unitholders as of the end of such period over (ii) the sum of those Members’ Share of Additional Book Basis Derivative Items for each prior taxable period.

Required Allocations” means (a) any limitation imposed on any allocation of Net Losses or Net Termination Losses under Section 6.1(b) and Section 6.1(c) and (b) any allocation of an item of income, gain, loss, deduction, Simulated Depletion or Simulated Loss pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

Residual Gain” or “Residual Loss” means any item of gain or loss or Simulated Gain or Simulated Loss, as the case may be, of the Company recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss or Simulated Gain or Simulated Loss is not allocated pursuant to Section 6.2(d)(i)(A) or Section 6.2(d)(ii)(A), respectively, to eliminate Book-Tax Disparities.

Second Target Distribution” has the meaning set forth in Section 6.4(b)(iii).

Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

Services Agreement” means the Services Agreement between Anthem Securities, Inc. and Atlas America of even date herewith, as the same may be amended from time to time.

Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, with respect to the Unitholders, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

Simulated Basis” means the Carrying Value of any oil and gas property (as defined in Section 614 of the Code).

Simulated Depletion” means, with respect to an oil and gas property (as defined in Section 614 of the Code), a depletion allowance computed in accordance with federal income tax principles (as if the Simulated Basis of the property were its adjusted tax basis) and in the manner specified in Treasury Regulation §1.704-1(b)(2)(iv)(k)(2). For purposes of computing Simulated Depletion with respect to any property, the Simulated Basis of such property shall be deemed to be the Carrying Value of such property, and in no event shall such allowance for Simulated Depletion, in the aggregate, exceed such Simulated Basis.

Simulated Gain” means the excess of the amount realized from the sale or other disposition of an oil or gas property over the Carrying Value of such property.

Simulated Loss” means the excess of the Carrying Value of an oil or gas property over the amount realized from the sale or other disposition of such property.

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Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general or limited) or limited liability company in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership or member of such limited liability company, but only if more than 50% of the partnership interests of such partnership or membership interests of such limited liability company (considering all of the partnership interests or membership interests as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation, partnership or limited liability company) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

Substituted Member” means a Person who is admitted as a Member pursuant to Section 4.5 in place of and with all rights of a Member and who is shown as a Member on the books and records of the Company.

Surviving Business Entity” has the meaning assigned to such term in Section 12.2(b)(ii).

Tax Matters Partner” means the Tax Matters Partner as defined in the Code.

Trading Day” means a day on which the principal National Securities Exchange on which Member Interests of any class are listed or admitted to trading is open for the transaction of business or, if Member Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“transfer” has the meaning assigned to such term in Section 4.4.

Transfer Agent” means such bank, trust company or other Person (including the Company or one of its Affiliates) as shall be appointed from time to time by the Company to act as registrar and transfer agent for the Common Units; provided that if no Transfer Agent is specifically designated for any other Company Securities, the Company shall act in such capacity.

Underwriter” means each Person named as an underwriter in the Underwriting Agreement who purchases Common Units pursuant thereto.

Underwriting Agreement” means that certain Underwriting Agreement, dated             , 2006, among the Underwriters, the Company and certain other parties, providing for the purchase of Common Units by the Underwriters.

Unit” means a Company Security that is designated as a “Unit” and shall include Class A Units and Common Units but shall not include the Management Incentive Interests.

Unit Majority” means at least a majority of the Outstanding Common Units and Class A Units, voting together as a single class.

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Unpaid IQD” has the meaning set forth in Section 6.1(c)(i)(B).

Unrealized Gain” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.4(c)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(c) as of such date).

Unrealized Loss” attributable to any item of Company property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.4(c) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.4(c))

Unrecovered Capital” means at any time, with respect to a Unit, the Issue Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of such Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Company theretofore made in respect of such Unit, adjusted as the Board of Directors determines to be appropriate to give effect to any distribution, subdivision or combination of such Units.

U.S. GAAP” means United States generally accepted accounting principles consistently applied.

Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Members made pursuant to a credit facility, commercial paper facility or other similar financing arrangement, provided that when it is incurred it is the intent of the borrower to repay such borrowings within 12 months from other than Working Capital Borrowings.

Section 1.2    Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms, and the singular form of nouns, pronouns and verbs shall include the plural and vice versa; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; and (c) the term “include” or “includes” means includes, without limitation, and “including” means including, without limitation.

Article 2

ORGANIZATION

Section 2.1    Formation.

The Company has previously been formed as a limited liability company pursuant to the provisions of the Delaware Act. Atlas America hereby amends and restates the Initial Operating Agreement in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Members and the administration, dissolution and termination of the Company shall be governed by the Delaware Act. All Member Interests shall constitute personal property of the owner thereof for all purposes and a Member has no interest in specific Company property.

Section 2.2    Name.

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“Limited Liability Company,” “LLC,” or similar words or letters shall be included in the Company’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The Board of Directors may change the name of the Company at any time and from time to time and shall notify the Members of such change in the next regular communication to the Members.

Section 2.3    Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the Board of Directors, the registered office of the Company in the State of Delaware shall be located at 110 S. Poplar Street, Suite 101, Wilmington, Delaware 19801, and the registered agent for service of process on the Company in the State of Delaware at such registered office shall be Andrew Lubin. The principal office of the Company shall be located at 311 Rouser Road, Moon Township, Pennsylvania, or such place as the Board of Directors may from time to time designate by notice to the Members. The Company may maintain offices at such other place or places within or outside the State of Delaware as the Board of Directors determines to be necessary or appropriate.

Section 2.4    Purposes and Business.

The purpose and nature of the business to be conducted by the Company shall be to (a) serve as a member, partner or stockholder, as the case may be, of, and hold limited liability company interests, partnership (whether general or limited) interests or stock, as the case may be, in the Operating Companies and, in connection therewith, to exercise all the rights and powers conferred upon the Company as a member or stockholder, as the case may be, of such entities, (b) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that the Operating Companies are permitted to engage in or that their Subsidiaries are permitted to engage in by their organizational documents or agreements, as amended or restated from time to time, and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity, (c) engage directly in, or enter into or form any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the Board of Directors and that lawfully may be conducted by a limited liability company organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Company pursuant to the agreements relating to such business activity; and (d) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the Company shall not engage, directly or indirectly, in any business activity that the Board of Directors determines would cause the Company to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. The Board of Directors has no obligation or duty to the Company or the Members to propose or approve, and may decline to propose or approve, the conduct by the Company of any business.

Section 2.5    Powers.

The Company shall be empowered to do any and all acts and things necessary and appropriate for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Company.

Section 2.6    Power of Attorney.

Each Member and Assignee hereby constitutes and appoints each of the Chief Executive Officer, the President and the Secretary and, if a Liquidator shall have been selected pursuant to Section 10.2, the Liquidator (and any successor to the Liquidator by merger, transfer, assignment, election or otherwise)


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and each of their authorized officers and attorneys-in-fact, as the case may be, with full power of substitution, as his true and lawful agent and attorney-in-fact, with full power and authority in his name, place and stead, to:

 

(a)   execute, swear to, acknowledge, deliver, file and record in the appropriate public offices:

 

  (i)   all certificates, documents and other instruments (including this Agreement and the Certificate of Formation and all amendments or restatements hereof or thereof) that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to form, qualify or continue the existence or qualification of the Company as a limited liability company in the State of Delaware and in all other jurisdictions in which the Company may conduct business or own property;

 

  (ii)   all certificates, documents and other instruments that the Chief Executive Officer, President or Secretary, or the Liquidator, determines to be necessary or appropriate to reflect, in accordance with its terms, any amendment, change, modification or restatement of this Agreement;

 

  (iii)   all certificates, documents and other instruments (including conveyances and a certificate of cancellation) that the Board of Directors, such Officer or the Liquidator determines to be necessary or appropriate to reflect the dissolution, liquidation and termination of the Company pursuant to the terms of this Agreement;

 

  (iv)   all certificates, documents and other instruments relating to the admission, withdrawal, removal or substitution of any Member pursuant to, or other events described in, Article 4 or Article 10;

 

  (v)   all certificates, documents and other instruments relating to the determination of the rights, preferences and privileges of any class or series of Company Securities issued pursuant to Section 5.5;

 

  (vi)   all certificates, documents and other instruments (including agreements and a certificate of merger) relating to a merger, consolidation or conversion of the Company pursuant to Article 12; and

 

(b)   execute, swear to, acknowledge, deliver, file and record all ballots, consents, approvals, waivers, certificates, documents and other instruments that the Board of Directors or the Liquidator determines to be necessary or appropriate to (i) make, evidence, give, confirm or ratify any vote, consent, approval, agreement or other action that is made or given by the Members hereunder or is consistent with the terms of this Agreement or (ii) effectuate the terms or intent of this Agreement; provided, that when required by Section 11.2 or any other provision of this Agreement that establishes a percentage of the Members or of the Members of any class or series required to take any action, the Chief Executive Officer, President or Secretary, or the Liquidator, may exercise the power of attorney made in this Section 2.6(b) only after the necessary vote, consent or approval of the Members or of the Members of such class or series, as applicable.

Nothing contained in this Section 2.6 shall be construed as authorizing the Chief Executive Officer, President or Secretary, or the Liquidator, to amend this Agreement except in accordance with Article 11 or as may be otherwise expressly provided for in this Agreement.

 

(c)   The foregoing power of attorney is hereby declared to be irrevocable and a power coupled with an interest, and it shall survive and, to the maximum extent permitted by law, not be affected by the subsequent death, incompetency, disability, incapacity, dissolution, bankruptcy or termination of any Member or Assignee and the transfer of all or any portion of such Member’s or Assignee’s Member Interest and shall extend to such Member’s or Assignee’s heirs, successors, assigns and personal representatives. Each such Member or Assignee hereby agrees to be bound by any

 

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representation made by the Chief Executive Officer, President or Secretary, or the Liquidator, acting in good faith pursuant to such power of attorney; and each such Member or Assignee, to the maximum extent permitted by law, hereby waives any and all defenses that may be available to contest, negate or disaffirm the action of the Chief Executive Officer, President or Secretary, or the Liquidator, taken in good faith under such power of attorney. Each Member or Assignee shall execute and deliver to the Chief Executive Officer, President or Secretary, or the Liquidator, within 15 days after receipt of the request therefor, such further designation, powers of attorney and other instruments as any of such Officers or the Liquidator, determines to be necessary or appropriate to effectuate this Agreement and the purposes of the Company.

Section 2.7    Term.

The Company’s term shall be perpetual, unless and until it is dissolved in accordance with the provisions of Article 10. The existence of the Company as a separate legal entity shall continue until the cancellation of the Certificate of Formation as provided in the Delaware Act.

Section 2.8    Title to Company Assets.

Title to Company assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, Director or Officer, individually or collectively, shall have any ownership interest in such Company assets or any portion thereof. Title to any or all of the Company assets may be held in the name of the Company, one or more of its Affiliates or one or more nominees, as the Board of Directors may determine. The Company hereby declares and warrants that any Company assets for which record title is held in the name of one or more of its Affiliates or one or more nominees shall be held by such Affiliates or nominees for the use and benefit of the Company in accordance with the provisions of this Agreement; provided, however, that the Board of Directors shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the Board of Directors determines that the expense and difficulty of conveyancing makes transfer of record title to the Company impracticable) to be vested in the Company as soon as reasonably practicable. All Company assets shall be recorded as the property of the Company in its books and records, irrespective of the name in which record title to such Company assets is held.

Article 3

RIGHTS OF MEMBERS

Section 3.1    Limitation of Liability.

As provided in Section 18-303 of the Delaware Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company. The Members shall have no liability under this Agreement, or for any such debt, obligation or liability of the Company, in their capacity as a Member, except as expressly required in this Agreement or the Delaware Act.

Section 3.2    Members.

 

(a)   Other than with regard to the Initial Members, a Person shall be admitted as a Member and shall become bound by the terms of this Agreement if such Person purchases or otherwise lawfully acquires any Member Interest and becomes the Record Holder of such Member Interest in accordance with the provisions of Article 4 hereof. A Person may become a Record Holder without the consent or approval of any of the Members. A Person may not become a Member without

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acquiring a Member Interest. Notwithstanding the foregoing, the rights and obligations of a Person who is a Non-citizen Assignee shall be determined in accordance with Section 4.7 hereof.

 

(b)   The name and mailing address of each Member shall be listed on the books and records of the Company maintained for such purpose by the Company or the Transfer Agent. The Secretary of the Company shall update the books and records of the Company from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Member’s Interest may be represented by a Certificate, as provided in Section 4.1 hereof.

 

(c)   Members may not be expelled from or removed as Members of the Company other than in accordance with Section 4.7 or Section 4.8. Members shall not have any right to resign from the Company; provided, that when a transferee of a Member’s Interest becomes a Record Holder of such Member Interest, such transferring Member shall cease to be a member of the Company with respect to the Member Interest so transferred.

Section 3.3    Management of Business.

No Member, in its capacity as such, shall participate in the operation or management of the Company’s business, transact any business in the Company’s name or have the power to sign documents for or otherwise bind the Company by reason of being a Member.

Section 3.4    Outside Activities of the Members.

Subject to the provisions or the Omnibus Agreement, any Member shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Company, including business interests and activities in direct competition with the Company Group. Neither the Company nor any of the other Members shall have any rights by virtue of this Agreement in any business ventures of any Member.

Section 3.5    Member Interests.

 

(a)   Pursuant to the terms of the Initial Operating Agreement, a single Member Interest is issued and outstanding as of the date of this Agreement, which Member Interest constitutes 100% of the Member Interests (the “Pre-IPO Member Interest”). The Pre-IPO Member Interest is owned of record by Atlas America. Immediately prior to the closing of the Initial Offering, the Pre-IPO Member Interest will be converted into and exchanged for             Class A Units,             Common Units and the Management Incentive Interests, such conversion and exchange to be effected in accordance with Section 5.1. At the closing of the Initial Offering, the Company will issue to the Underwriters (i) the number of Common Units determined in accordance with Section 5.2(a), such issuance to be effected in accordance with Section 5.2(a), and (ii) if the Over-Allotment Option is exercised and the closing of such exercise occurs concurrently with closing of the Initial Offering, such additional number of Common Units as is determined in accordance with Section 5.2(b). The rights and obligations of the Class A Units, Common Units and Management Incentive Interests shall be as specified in this Agreement.

 

(b)   Immediately after the closing of the Initial Offering and as a result of the transactions referred to in Section 3.5(a), the Member Interests of the Company shall be comprised of three classes of Company Securities. The Class A Member Interests and Class B Member Interests shall be issued in equal, whole unit increments. Pursuant to the transactions to be effected on the Closing Date, the Company will issue the following:

 

  (i)   up to             Class A Units representing Class A Member Interests;

 

  (ii)   up to             Common Units representing Class B Member Interests; and

 

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(c)   the Class C Member Interests which constitute, and are referred to herein as the Management Incentive Interests.

Section 3.6    Respective Voting Rights of Classes of Units and Interests.

 

(a)   The Record Holder(s) of a Class A Unit(s) who have been admitted as Members of the Company in respect of such Class A Unit(s) shall have one vote per Class A Unit and be entitled to vote on all matters with respect to which a holder of Class A Units is entitled to vote under this Agreement.

 

(b)   The Record Holder(s) of a Common Unit(s) who have been admitted as Members of the Company in respect of such Common Unit(s) shall have one vote per Common Unit and be entitled to vote on all matters with respect to which a holder of Common Units is entitled to vote under this Agreement.

 

(c)   The Management Incentive Interests shall constitute non-voting Member Interests in the Company except to the extent required by applicable law.

 

(d)   A holder of any Unit who has not been admitted as a Member in accordance with this Agreement shall not be entitled to vote on any matters, and any Member who becomes a Non-citizen Assignee shall be subject to the voting restrictions set forth in Section 4.7.

 

(e)   Except as set forth in this Agreement or as required by law, holders of Units and other Member Interests or Company Securities shall have no voting rights and their consent shall not be required for taking any action, including the merger, consolidation or conversion of the Company.

Section 3.7    Conversion of Class A Units and Management Incentive Interests.

 

(a)   Concurrently with any termination of the right of the holder(s) of the Class A Unit(s) to class voting pursuant to Section 11.8(d) that is not supported by the affirmative vote of any Common Units held by the holders of a majority of the Outstanding Class A Units or a majority of the Outstanding Management Incentive Interests or their Affiliates, then:

 

  (i)   each Outstanding Class A Unit shall automatically convert into, and shall thereafter constitute, one Common Unit; and

 

  (ii)   the holder(s) of the Management Incentive Interests shall have the right, exercisable upon notice to the Company delivered at any time within 180 days thereafter, to require the conversion by the Company of the Management Incentive Interests into a number of Common Units, the fair market value of which is equal to the fair market value of such Management Incentive Interests. For purposes of this Section 3.7(a)(ii), the fair market value of the Management Incentive Interests shall be determined by agreement between the holder(s) thereof and the Conflicts Committee or, failing agreement within 30 days after the holder(s)’ demand for conversion, by an independent investment banking firm or other independent expert selected by the holder(s) and the Conflicts Committee, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the holder(s)’ demand for conversion, then each of the holder(s) and the Conflicts Committee shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Management Incentive Interests.

 

(b)   The Class A Units and Management Incentive Interests shall also be convertible into Common Units pursuant to the Management Agreement.

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(c)   The transfer of a Class A Unit or Management Incentive Interests that have converted into a Common Unit shall be subject to the restrictions imposed by the Board of Directors necessary to preserve the uniformity of units, including the application of Section 6.2(e).

Section 3.8    Rights of Members.

 

(a)   In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.8(b), each Member shall have the right, for a lawful purpose reasonably related to such Member’s Member Interest as a Member in the Company, upon reasonable written demand containing a concise statement of such purposes and at such Member’s own expense:

 

  (i)   to obtain true and full information regarding the status of the business and financial condition of the Company;

 

  (ii)   promptly after becoming available, to obtain a copy of the Company’s federal, state and local income tax returns for each year;

 

  (iii)   to have furnished to him a current list of the name and last known business, residence or mailing address of each Member;

 

  (iv)   to have furnished to him a copy of this Agreement and the Certificate of Formation and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Formation and all amendments thereto have been executed;

 

  (v)   to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Member and that each Member has agreed to contribute in the future, and the date on which each became a Member; and

 

  (vi)   to obtain such other information regarding the affairs of the Company as is just and reasonable and consistent with the stated purposes of the written demand.

 

(b)   The Board of Directors may keep confidential from the Members, for such period of time as the Board of Directors determines, (i) any information that the Board of Directors determines to be in the nature of trade secrets or (ii) other information (including the Social Security Number or Tax Identification Number of any Member) the disclosure of which the Board of Directors determines (A) is not in the best interests of the Company Group, (B) could damage the Company Group or (C) that any Group Member is required by law, by the rules of any National Securities Exchange on which any Company Security is listed for trading, or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Company the primary purpose of which is to circumvent the obligations set forth in this Section 3.8).

Article 4

CERTIFICATES; RECORD HOLDERS; TRANSFER OF INTERESTS; REDEMPTION OF INTERESTS

Section 4.1    Certificates.

Upon the Company’s issuance of Common Units to any Person, the Company may issue one or more Certificates in the name of such Person evidencing the number of such Common Units being so issued. In addition, upon the request of any Person owning any other Company Securities other than Common


 

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Units, the Company shall issue to such Person one or more Certificates evidencing such other Company Securities. Certificates shall be executed on behalf of the Company by the Chairman of the Board, President or any Vice President and the Secretary or any Assistant Secretary. No Certificate representing Common Units shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the Board of Directors elects to issue Common Units in global form, the Common Unit Certificates shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Common Units have been duly registered in accordance with the directions of the Company. Any or all of the signatures required on the Certificate may be by facsimile. If any Officer or Transfer Agent who shall have signed or whose facsimile signature shall have been placed upon any such Certificate shall have ceased to be such Officer or Transfer Agent before such Certificate is issued by the Company, such Certificate may nevertheless be issued by the Company with the same effect as if such Person were such Officer or Transfer Agent at the date of issue. Certificates shall be consecutively numbered and shall be entered on the books and records of the Transfer Agent as they are issued and shall exhibit the holder’s name and number and type of Company Securities represented thereby.

Section 4.2    Mutilated, Destroyed, Lost or Stolen Certificates.

If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate Officers on behalf of the Company shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Company Securities as the Certificate so surrendered.

 

(a)   The appropriate Officers on behalf of the Company shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

 

  (i)   makes proof by affidavit, in form and substance satisfactory to the Company, that a previously issued Certificate has been lost, destroyed or stolen;

 

  (ii)   requests the issuance of a new Certificate before the Company has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

 

  (iii)   if requested by the Company, delivers to the Company a bond, in form and substance satisfactory to the Company, with surety or sureties and with fixed or open penalty as the Company may direct to indemnify the Company and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

 

  (iv)   satisfies any other reasonable requirements imposed by the Company.

If a Member fails to notify the Company within a reasonable time after he has notice of the loss, destruction or theft of a Certificate, and a transfer of the Member Interests represented by the Certificate is registered before the Company or the Transfer Agent receives such notification, the Member shall be precluded from making any claim against the Company or the Transfer Agent for such transfer or for a new Certificate.

 

(b)   As a condition to the issuance of any new Certificate under this Section 4.2, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3    Record Holders.

The Company shall be entitled to recognize the Record Holder as the owner of a Member Interest and, accordingly, shall not be bound to recognize any equitable or other claim to or interest in such Member


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Interest on the part of any other Person, regardless of whether the Company shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Member Interests are listed for trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Member Interests, as between the Company on the one hand, and such other Persons on the other, such representative Person shall be the Record Holder of such Member Interest.

Section 4.4    Transfer Generally.

The term transfer,” when used in this Agreement with respect to a Member Interest, shall be deemed to refer to any transaction pursuant to which the Company issues any Member Interest or by which the holder of a Member Interest assigns such Member Interest to another Person who is or becomes a Member, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise,

including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage. Other than with respect to an assignment by Atlas America of its Class A Units and Management Incentive Interests to Atlas Energy Management immediately following the execution of this Agreement on the Closing Date, no Member Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article 4. Any transfer or purported transfer of a Member Interest not made in accordance with this Article 4 shall be, to the fullest extent permitted by law, null and void.

Section 4.5    Registration and Transfer of Member Interests.

 

(a)   The Company shall keep or cause to be kept on behalf of the Company a register that, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), will provide for the registration and transfer of Member Interests. The Transfer Agent is hereby appointed registrar and transfer agent for the purpose of registering Common Units and transfers of such Common Units as herein provided. The Company shall not recognize transfers of Certificates evidencing Member Interests unless such transfers are effected in the manner described in this Section 4.5. Upon surrender of a Certificate for registration of transfer of any Member Interests evidenced by a Certificate, and subject to the provisions of Section 4.5(b), the appropriate Officers of the Company shall execute and deliver, and in the case of Common Units, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the Record Holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Member Interests as were evidenced by the Certificate so surrendered.

 

(b)   Except as provided in Section 4.7, the Company shall not recognize any transfer of Member Interests until the Certificates evidencing such Member Interests are surrendered for registration of transfer. No charge shall be imposed by the Company for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5(b), the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto.

 

(c)   By acceptance of the transfer of any Member Interest in accordance with this Section 4.5 and except as provided in Section 4.7, each transferee of a Member Interest (including any nominee holder or an agent or representative acquiring such Member Interests for the account of another Person) (i) shall be admitted to the Company as a Substituted Member with respect to the Member Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Company, with or without execution of this Agreement, (ii) shall be deemed to agree to be bound by the terms of this Agreement, (iii) shall become the Record Holder of the Member

 

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Interests so transferred, (iv) represents that the transferee has the capacity, power and authority to enter into this Agreement, (v) grants powers of attorney to the Officers of the Company and any Liquidator of the Company in accordance with Section 2.6, and (vi) makes the consents and waivers contained in this Agreement. The transfer of any Member Interests and the admission of any new Member shall not constitute an amendment to this Agreement.

Section 4.6    Restrictions on Transfers.

 

(a)   In addition to the restrictions set forth in Section 4.5(b) and except as provided in Section 4.6(c)(b) below, but notwithstanding the other provisions of this Article 4, no transfer of any Member Interests shall be made if such transfer would violate the then applicable federal or state securities laws or rules and regulations of the Securities and Exchange Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer.

 

(b)   In addition to the restrictions set forth in Section 4.5(b), the Company may impose restrictions on the transfer of Member Interests if it receives an Opinion of Counsel providing that such restrictions
  are necessary to avoid a significant risk of any Group Member becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The Board of Directors may impose such restrictions by amending this Agreement in accordance with Article 11; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Member Interests on the principal National Securities Exchange on which such class of Member Interests is then traded must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Member Interests of such class.

 

(c)   Nothing contained in this Article 4, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Member Interests entered into through the facilities of any National Securities Exchange on which such Member Interests are listed for trading.

 

(d)   Subject to (i) the foregoing provisions of this Section 4.6, (ii) Section 4.3, (iii) Section 4.5, (iv) with respect to any class or series of Member Interests other than the Class A Units, Common Units and Management Incentive Interests, the provisions of any amendment to this Agreement containing the statement of designations establishing such class or series, (v) the provisions of the Management Agreement and any other contractual provision binding on any Member and (vi) provisions of applicable law including the Securities Act, Member Interests shall be freely transferable to any Person.

Section 4.7    Citizenship Certificates; Non-citizen Assignees.

 

(a)   If any Group Member is or becomes subject to any federal, state or local law or regulation that the Board of Directors determines would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Member or Assignee, the Board of Directors may request any Member or Assignee to furnish to the Board of Directors, within 30 days after receipt of such request, an executed Citizenship Certification or such other information concerning his nationality, citizenship or other related status (or, if the Member or Assignee is a nominee holding for the account of another Person, the nationality, citizenship or other related status of such Person) as the Board of Directors may request. If a Member or Assignee fails to furnish to the Board of Directors within such 30-day period such Citizenship Certification or other requested information or if upon receipt of such Citizenship Certification or other requested information the Board of Directors determines that a Member or Assignee is not an Eligible Citizen, the Member Interests owned by such Member or Assignee shall be subject to redemption in accordance with the provisions of Section 4.8. In addition, the Board of Directors may require that the status of any such Member or Assignee be changed to that of a Non-citizen Assignee and, thereupon, such Member shall cease to be a member

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of the Company and shall have no voting rights, whether arising hereunder, under the Delaware Act, at law, in equity or otherwise, in respect of its Member Interests. The voting rights in respect of Member Interests of Non-citizen Assignees shall be deemed to have been exercised with the votes being distributed in the same ratios or for the same candidates for election as Directors as the votes of Members in respect of Member Interests other than those of Non-citizen Assignees are cast, either for, against or abstaining as to the matter or election.

 

(b)   Upon dissolution of the Company, a Non-citizen Assignee shall have no right to receive a distribution in kind pursuant to Section 10.3, but shall be entitled to the cash equivalent thereof, and the Company shall provide cash in exchange for an assignment of the Non-citizen Assignee’s share of any distribution in kind. Such payment and assignment shall be treated for Company purposes as a purchase by the Company from the Non-citizen Assignee of his economic interest in the Company (representing his right to receive his share of such distribution in kind).

 

(c)   At any time after he can and does certify that he has become an Eligible Citizen, a Non-citizen Assignee may, upon application to the Board of Directors, request admission as a Substituted Member with respect to any Member Interests of such Non-citizen Assignee not redeemed pursuant to Section 4.8, such Non-citizen Assignee be admitted as a Member, and upon approval of the Board of Directors, such Non-citizen Assignee shall be admitted as a Member and shall no longer constitute a Non-citizen Assignee and shall reacquire all voting rights of his Member Interests.

Section 4.8    Redemption of Member Interests of Non-citizen Assignees.

 

(a)   If at any time a Member or Assignee fails to furnish a Citizenship Certification or other information requested within the 30-day period specified in Section 4.7(a), or if upon receipt of such Citizenship Certification or other information the Board of Directors determines, with the advice of counsel, that a Member or Assignee is not an Eligible Citizen, the Company may, unless the Member or Assignee establishes to the satisfaction of the Board of Directors that such Member or Assignee is an Eligible Citizen or has transferred his Member Interests to a Person who is an Eligible Citizen and who furnishes a Citizenship Certification to the Board of Directors prior to the date fixed for redemption as provided below, redeem the Member Interest of such Member or Assignee as follows:

 

  (i)   The Board of Directors shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Member or Assignee, at his last address designated on the records of the Company or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Member would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

 

  (ii)   The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Member Interests of the class to be so redeemed multiplied by the number of Member Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the Board of Directors, in cash or by delivery of a promissory note of the Company in the principal amount of the redemption price, bearing interest at the Prime Rate annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

 

  (iii)   Upon surrender by or on behalf of the Member or Assignee, at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or

 

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accompanied by an assignment duly executed in blank, the Member or Assignee or his duly authorized representative shall be entitled to receive the payment therefor.

 

  (iv)   After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Member Interests.

 

(b)   The provisions of this Section 4.8 shall also be applicable to Member Interests held by a Member or Assignee as nominee of a Person determined to be other than an Eligible Citizen.

 

(c)   Nothing in this Section 4.8 shall prevent the recipient of a notice of redemption from transferring his Member Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the Board of Directors shall withdraw the notice of redemption, provided the transferee of such Member Interest certifies to the satisfaction of the Board of Directors in a Citizenship Certification that he is an Eligible Citizen. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

Article 5

CAPITAL CONTRIBUTIONS AND ISSUANCE OF INTERESTS

Section 5.1    Redemption or Exchange of the Pre-IPO Member Interests.

On the Closing Date and immediately prior to the closing of the Initial Offering, Atlas America’s Pre-IPO Member Interest shall be converted into and exchanged for [            ] Common Units. On the Closing Date and concurrently with the closing of the Initial Offering, Atlas America shall contribute to the Company the assets described in the Contribution Agreement in exchange for the issuance to Atlas America of [            ] Class A Units, [            ] Common Units and the Management Incentive Interests and the right to receive $            . Concurrently with such issuance, Atlas America shall transfer the Class A Units and the Management Incentive Interests to Atlas Energy Management.

Section 5.2    Contributions by the Underwriters.

 

(a)   On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Closing Date. In consideration for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made a number of Common Units equal to the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of the Common Units so issued to such Underwriter.

 

(b)   Upon the exercise of the Over-Allotment Option and pursuant to the Underwriting Agreement, each Underwriter shall contribute to the Company cash in an amount equal to the Issue Price per Initial Common Unit, multiplied by the number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter at the Option Closing Date. In exchange for such Capital Contributions by the Underwriters, the Company shall issue Common Units to each Underwriter on whose behalf such Capital Contribution is made, a number of Common Units specified in the Underwriting Agreement to be purchased by such Underwriter on the Option Closing Date, and upon such issuance such Underwriter shall be admitted to the Company as a Member in respect of

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the Common Units so issued to such Underwriter pursuant to this Section 5.2(b). Upon receipt by the Company of the Capital Contributions from the Underwriters as provided in this Section 5.2(b), the Company shall use such cash to purchase from Atlas America, and Atlas America agrees to sell to the Company, at the Issue Price per Initial Common Unit a number of Common Units equal to the number of Common Units issued to the Underwriters in accordance with this Section 5.2(b).

Section 5.3    Interest and Withdrawal.

No interest shall be paid by the Company on Capital Contributions. No Member shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon dissolution of the Company may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Member shall have priority over any other Member either as to the return of Capital Contributions or as to profits, losses or distributions.

Section 5.4    Capital Accounts.

 

(a)   The Company shall maintain for each Member (or a beneficial owner of Member Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company
  in accordance with Section 6031(c) of the Code or any other method acceptable to the Company) owning a Member Interest a separate Capital Account with respect to such Member Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Company with respect to such Member Interest pursuant to this Agreement and (ii) all items of Company income and gain (including Simulated Gain and income and gain exempt from tax) computed in accordance with Section 5.4(b) and allocated with respect to such Member Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Member Interest pursuant to this Agreement and (y) all items of Company deduction and loss (including Simulated Depletion and Simulated Loss) computed in accordance with Section 5.4(b) and allocated with respect to such Member Interest pursuant to Section 6.1.

 

(b)   For purposes of computing the amount of any item of income, gain, loss or deduction, Simulated Depletion, Simulated Gain or Simulated Loss which is to be allocated pursuant to Article 6 and is to be reflected in the Members’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

 

  (i)   Solely for purposes of this Section 5.4, the Company shall be treated as owning directly its proportionate share (as determined by the Board of Directors based upon the provisions of the applicable Group Member Agreement) of all property owned by any other Group Member that is classified as a partnership for federal income tax purposes.

 

  (ii)   All fees and other expenses incurred by the Company to promote the sale of (or to sell) a Member Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Members pursuant to Section 6.1.

 

  (iii)   Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain

 

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and Simulated Loss shall be made without regard to any election under Section 754 of the Code which may be made by the Company and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

 

  (iv)   Any income, gain, loss, Simulated Gain or Simulated Loss attributable to the taxable disposition of any Company property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Company’s Carrying Value with respect to such property as of such date.

 

  (v)   In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery amortization or Simulated Depletion attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Company were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.4(d) to the Carrying Value of any Company property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery, amortization or Simulated Depletion attributable to such property shall be determined (A) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment and (B) using any method of depreciation, cost recovery, amortization or Simulated Depletion that the Board of Directors may adopt.

 

  (vi)   If the Company’s adjusted basis in a depreciable or cost recovery property is reduced for federal income tax purposes pursuant to Section 48(q)(1) or 48(q)(3) of the Code, the amount of such reduction shall, solely for purposes hereof, be deemed to be an additional depreciation or cost recovery deduction in the year such property is placed in service and shall be allocated among the Members pursuant to Section 6.1. Any restoration of such basis pursuant to Section 48(q)(2) of the Code shall, to the extent possible, be allocated in the same manner to the Members to whom such deemed deduction was allocated.

 

(c)   A transferee of a Member Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Member Interest so transferred.

 

  (i)   In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Member Interests for cash or Contributed Property and the issuance of Member Interests as consideration for the provision of services, the Capital Account of all Members and the Carrying Value of each Company property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such issuance and had been allocated to the Members at such time pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to the issuance of additional Member Interests shall be determined by the Board of Directors using such method of valuation as it may adopt; provided, however, that the Board of Directors, in arriving at such valuation, must take fully into account the fair market value of the Member Interests of all Members at such time. The Board of Directors shall allocate such

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aggregate value among the assets of the Company (in such manner as it determines) to arrive at a fair market value for individual properties.

 

  (ii)   In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Member of any Company property (other than a distribution of cash that is not in redemption or retirement of a Member Interest), the Capital Accounts of all Members and the Carrying Value of all Company property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Company property, as if such Unrealized Gain or Unrealized Loss had been recognized in a sale of such property immediately prior to such distribution for an amount equal to its fair market value, and had been allocated to the Members, at such time, pursuant to Section 6.1 in the same manner as any item of gain, loss, Simulated Gain or Simulated Loss actually recognized during such period would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Company assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 10.3 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.4(c)(i) or (B) in the case of a liquidating distribution pursuant to Section 10.3, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.5    Issuances of Additional Company Securities.

 

(a)   Subject to Section 5.6, at any time or from time to time after the closing of the Initial Offering the Company may issue additional Company Securities, and options, rights, warrants and appreciation rights relating to the Company Securities for any Company purpose to such Persons, and admit such Persons as members of the Company, for such consideration and on such terms and conditions as the Board of Directors shall determine in its sole discretion, all without the approval of the Members of any class of Company Securities then Outstanding.

 

(b)   Each additional Company Security authorized to be issued by the Company pursuant to Section 5.5(a) may be issued in one or more classes, or one or more series of any such classes, with such relative 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 then Outstanding class and series of Company Securities), as shall be fixed by the Board of Directors, including (i) the right to share Company profits and losses or items thereof; (ii) the right to share in Company distributions; (iii) the rights upon dissolution and liquidation of the Company; (iv) whether, and the terms and conditions upon which, the Company may redeem the Company Security, including sinking fund provisions, if any; (v) whether such Company Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Company Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Company Security; and (viii) the right, if any, of the holders of each such Company Security to vote on Company matters, including matters relating to the relative rights, preferences and privileges of such Company Security. Notwithstanding anything in this Agreement to the contrary, additional Company Securities, issuable without the approval of the Members of any class of Company Securities then Outstanding, may include (i) Company Securities with preferences, rights, powers and duties (including rights to distributions, allocations, voting or in liquidation) that are senior or prior, pari passu or junior to any other class or series of Company Securities then Outstanding, or (ii) additional Company Securities of any class or series then Outstanding.

 

(c)   The Board of Directors shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Company Securities and options, rights, warrants and

 

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appreciation rights relating to Company Securities pursuant to this Section 5.5, (ii) the conversion of Class A Units and Management Incentive Interests into Common Units pursuant to the terms of this Agreement, (iii) the admission of any Person(s) as an Additional Member(s) and (iv) all additional issuances of Company Securities. The Board of Directors shall determine the relative designations, preferences, rights, powers and duties of the holders of the Units or other Company Securities being so issued. The Board of Directors shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Company Securities pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Common Units or other Company Securities are listed for trading.

Section 5.6    Limitations on Issuance of Additional Company Securities.

The issuance of Company Securities pursuant to Section 5.5 shall be subject to the limitation that no fractional Units shall be issued by the Company.

Section 5.7    No Preemptive Rights.

No Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Company Security, whether unissued, held by the Company or hereafter created.

Section 5.8    Splits and Combinations.

 

(a)   Subject to Section 5.6, Section 5.8(d) and Section 6.7, the Company may make a Pro Rata distribution of Company Securities of any class or series to all Record Holders of Company Securities of such class or series or may effect a subdivision or combination of Company Securities so long as, after any such event, each Member shall have the same Percentage Interest in the Company as before such event, and any amounts calculated on a per Unit basis or stated as a number of Units are proportionately adjusted retroactive to the date of formation of the Company.

 

(b)   Whenever such a distribution, subdivision or combination of Company Securities is declared, the Board of Directors shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The Board of Directors also may cause a firm of independent public accountants selected by it to calculate the number of Company Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The Board of Directors shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

 

(c)   Promptly following any such distribution, subdivision or combination, the Company may issue Certificates to the Record Holders of Company Securities as of the applicable Record Date representing the new number of Company Securities held by such Record Holders, or the Board of Directors may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Company Securities Outstanding, the Company shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

 

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fractional Units but for the provisions of Section 5.6 and this Section 5.8(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

Section 5.9    Fully Paid and Non-Assessable Nature of Member Interests.

All Member Interests issued pursuant to, and in accordance with the requirements of, this Article 5 shall be validly issued, fully paid and non-assessable Member Interests in the Company, except as such non-assessability may be affected by Sections 18-607 or 18-804 of the Delaware Act and except to the extent otherwise provided in this Agreement.

Section 5.10    Registration Rights of Atlas America and its Affiliates.

 

(a)   If (i) Atlas Energy Management, Atlas America or any of their Affiliates (including for purposes of this Section 5.10, any Person that is an Affiliate of Atlas Energy Management or Atlas America at the date hereof notwithstanding that it may later cease to be an Affiliate of Atlas Energy Management or Atlas America) holds Company Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Company Securities (the “Holder”) to dispose of the number of Company Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Company shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period following its effective date until all Company Securities covered by such registration statement have
  been sold or until Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) becomes available for such Company Securities, a registration statement under the Securities Act registering the offering and sale of the number of Company Securities specified by the Holder (which registration statement may constitute a “shelf” registration statement covering the Company Securities specified by the Holder on an appropriate form under Rule 415 under the Securities Act, or any similar rule that may be adopted by the Commission); provided, however, that the Company shall not be required to effect more than three registrations pursuant to this Section 5.10(a); and provided further, however, that if the Conflicts Committee determines in good faith that the requested registration, or use of any prospectus forming a part thereof, would be materially detrimental to the Company and its Members because such registration would (x) materially interfere with a significant acquisition, reorganization or other similar transaction involving the Company, (y) require premature disclosure of material information that the Company has a bona fide business purpose for preserving as confidential or (z) render the Company unable to comply with requirements under applicable securities laws, then the Company shall have the right to postpone such requested registration or use of any such prospectus for a period of not more than three months after receipt of the Holder’s request, such right to postpone a requested registration or use of any such prospectus pursuant to this Section 5.10(a) not to be utilized more than once in any twelve-month period. Except as provided in the preceding sentence, the Company shall be deemed not to have used all commercially reasonable efforts to keep the registration statement effective during the applicable period if it voluntarily takes any action that would result in Holders of Company Securities covered thereby not being able to offer and sell such Company Securities at any time during such period, unless such action is required by applicable law. In connection with any registration pursuant to this Section 5.10(a), the Company shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Company would become subject to general service of process or to taxation or qualification to

 

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do business as a foreign corporation, limited liability company or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Company Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Company Securities in such states. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

 

(b)   If the Company shall at any time propose to file a registration statement under the Securities Act for an offering of equity securities of the Company for cash (other than an offering relating solely to an employee benefit plan or a business combination), the Company shall use all commercially reasonable efforts to include such number or amount of securities held by any Holder in such registration statement as the Holder shall request; provided, that the Company is not required to make any effort or take any action to so include the securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 5.10(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Company and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Company Securities, in addition to the equity securities of the Company that the Company proposes to sell, would adversely and materially affect the success of the offering, the Company shall include in such offering only that number or amount, if any, of securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 5.10(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Company, without reimbursement by the Holder.

 

(c)   If underwriters are engaged in connection with any registration referred to in this Section 5.10, the Company shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Company’s obligation under Section 7.7, the Company shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 5.10(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Company Securities were registered under the Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or in any amendment or supplement thereto (if used during the period the Company is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Company shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or

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alleged omission made in such registration statement, such preliminary, summary or final prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Company by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

 

(d)   The rights to cause the Company to register Company Securities pursuant to this Section 5.10 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Company Securities, provided (i) the Company is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Company Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 5.10.

 

(e)   Any request to register Company Securities pursuant to this Section 5.10 shall (i) specify the Company Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Company Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Company Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Company to comply with all applicable requirements in connection with the registration of such Company Securities.

Article 6

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1    Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Members among themselves, the Company’s items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss (computed in accordance with Section 5.4(b)) shall be allocated among the Members in each taxable year (or portion thereof) as provided herein below.

 

(a)   Net Income.    After giving effect to the special allocations set forth in Section 6.1(d), Net Income for each taxable year and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Income for such taxable year shall be allocated to the Unitholders in accordance with their respective Percentage Interests.

 

(b)   Net Losses.    After giving effect to the special allocations set forth in Section 6.1(d), Net Losses for each taxable period and all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Losses for such taxable period shall be allocated to the Unitholders in accordance with their respective Percentage Interests; provided that Net Losses shall not be allocated pursuant to this Section 6.1(b) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable year (or increase any existing deficit balance in its Adjusted Capital Account).

 

(c)   Net Termination Gains and Losses.    After giving effect to the special allocations set forth in Section 6.1(d), all items of income, gain, loss, deduction, Simulated Depletion, Simulated Gain and Simulated Loss taken into account in computing Net Termination Gain or Net Termination Loss for such taxable period shall be allocated in the same manner as such Net Termination Gain or Net Termination Loss is allocated hereunder. All allocations under this Section 6.1(c) shall be made after

 

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Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 10.3.

 

  (i)   If a Net Termination Gain is recognized (or deemed recognized pursuant to Section 5.4(c)), such Net Termination Gain shall be allocated among the Members in the following manner (and the Capital Accounts of the Members shall be increased by the amount so allocated in each of the following subclauses, in the order listed, before an allocation is made pursuant to the next succeeding subclause):

 

  (A)   First, to each Member having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Members, until each such Member has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

 

  (B)   Second, 98% to the holders of Common Units, Pro Rata, and 2% to the holders of Class A Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to (1) its Unrecovered Capital plus (2) the Initial Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter defined as the “Unpaid IQD”);

 

  (C)   Third, 98% to the holders of Common Units, Pro Rata, and 2% to the holders of Class A Units, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Capital, (2) the Unpaid IQD and (3) the excess of (a) the First Target Distribution less the Initial Quarterly Distribution for each Quarter of the Company’s existence over (b) the amount of any distributions of Available Cash made pursuant to Section 6.4(a) in excess of the Initial Quarterly Distribution for each Quarter during the MII Vesting Period and any distributions previously made pursuant to Section 6.4(b)(ii) (the sum of (1), (2) and (3) is hereinafter defined as the “First Liquidation Target Amount”);

 

  (D)   Fourth, 83% to the holders of Common Units, Pro Rata, 2% to the holders of Class A Units, Pro Rata, and 15% to the holders of the Management Incentive Interests, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount and (2) the excess of (a) the Second Target Distribution less the First Target Distribution for each Quarter of the Company’s existence over (b) the amount of any distributions of Available Cash made pursuant to Section 6.4(a) in excess of the First Target Distribution for each Quarter during the MII Vesting Period and any distributions previously made pursuant to Section 6.4(b)(iii); and

 

  (E)   Thereafter, 2% to the holders of Class A Units, Pro Rata, 73% to the holders of Common Units, Pro Rata, and 25% to the holders of the Management Incentive Interests, Pro Rata.

 

  (ii)   If a Net Termination Loss is recognized (or deemed recognized pursuant to Section 5.4(c)), such Net Termination Loss shall be allocated among the Members in the following manner:

 

  (A)   First, to the Unitholders, Pro Rata, until the Capital Account in respect of each Common Unit then Outstanding has been reduced to zero; and

 

  (B)   Second, the balance, if any, 100% to all Unitholders in accordance with their respective Percentage Interests.

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(d)   Special Allocations.    Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

 

  (i)   Company Minimum Gain Chargeback.    Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Company Minimum Gain during any Company taxable period, each Member shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to
  Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Company Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

 

  (ii)   Chargeback of Member Nonrecourse Debt Minimum Gain.    Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any Company taxable period, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Company income, gain and Simulated Gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections
  1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Member’s Adjusted Capital Account balance shall be determined, and the allocation of income, gain and Simulated Gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

 

  (iii)   Priority Allocations.

 

  (A)   Items of Company gross income or gain for the taxable period, if any, shall be allocated to the holders of the Management Incentive Interests, Pro Rata, until the aggregate amount of such items allocated to the holders of the Management Incentive Interests pursuant to this Section 6.1(d)(iii)(A) for the current taxable year and all previous taxable years is equal to the cumulative amount of all EP MIDs distributed pursuant to Section 6.5.

 

  (B)   After application of Section 6.1(d)(iii)(A), all or a portion of the remaining items of Company gross income or gain for the taxable period, if any, shall be allocated (1) to the holders of the Management Incentive Interests, Pro Rata, until the aggregate amount of such items allocated to the holders of the Management Incentive Interests pursuant to this Section 6.1(d)(iii)(B) for the current taxable year and all previous taxable years is equal to the cumulative amount of all Management Incentive Distributions made pursuant to Section 6.4(b)(iii)(C) from the Closing Date to a date 45 days after the end of the current taxable year and (2) to the Class A Units, Pro Rata, in an amount equal to 2/98ths of the sum of the amounts allocated in clause (1) above.

 

  (iv)   Qualified Income Offset.    In the event any Member unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Company income, gain and Simulated

 

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Gain shall be specially allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or (ii).

 

  (v)   Gross Income Allocations.    In the event any Member has a deficit balance in its Capital Account at the end of any Company taxable period in excess of the sum of (A) the amount such Member is required to restore pursuant to the provisions of this Agreement and (B) the amount such Member is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Member shall be specially allocated items of Company gross income, gain and Simulated Gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Member would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

 

  (vi)   Nonrecourse Deductions.    Nonrecourse Deductions for any taxable period shall be allocated to the Members in accordance with their respective Percentage Interests. If the Board of Directors determines that the Company’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the Board of Directors is authorized, upon notice to the other Members, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

 

  (vii)   Member Nonrecourse Deductions.    Member Nonrecourse Deductions for any taxable period shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, such Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss.

 

  (viii)   Nonrecourse Liabilities.    For purposes of Treasury Regulation Section 1.752-3(a)(3), the Members agree that Nonrecourse Liabilities of the Company in excess of the sum of (A) the amount of Company Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Members in accordance with their respective Percentage Interests.

 

  (ix)   Code Section 754 Adjustments.    To the extent an adjustment to the adjusted tax basis of any Company asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain or Simulated Gain (if the adjustment increases the basis of the asset) or loss or Simulated Loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Members in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

 

  (x)   Curative Allocation.

 

  (A)   Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of income, gain, loss,

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deduction, Simulated Depletion, Simulated Gain or Simulated Loss allocated to each Member pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Member under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. Notwithstanding the preceding sentence, Required Allocations relating to (1) Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Company Minimum Gain and (2) Member Nonrecourse Deductions shall not be taken into account except to the extent that there has been a decrease in Member Nonrecourse Debt Minimum Gain. Allocations pursuant to this Section 6.1(d)(x)(A) shall only be made with respect to Required Allocations to the extent the Board of Directors reasonably determines that such allocations will otherwise be inconsistent with the economic agreement among the Members. Further, allocations pursuant to this Section 6.1(d)(x)(A) shall be deferred with respect to allocations pursuant to clauses (1) and (2) hereof to the extent the Board of Directors determines that such allocations are likely to be offset by subsequent Required Allocations.

 

  (B)   The Board of Directors shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(x)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(x)(A) among the Members in a manner that is likely to minimize such economic distortions.

 

  (xi)   Corrective Allocations.    In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

 

  (A)   In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.4(c) hereof) to only certain Members (the “Allocated Members”), the Board of Directors shall allocate additional items of gross income, gain and Simulated Gain away from the Allocated Members to the extent that the Additional Book Basis Derivative Items allocated to the Allocated Members exceed their Share of Additional Book Basis Derivative Items and to the remaining Members (or shall allocate additional items of deduction, loss, Simulated Depletion and Simulated Loss away from the other Members and to the Allocated Members). For this purpose, a Member shall be treated as having been allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that otherwise have been allocated to the Member under this Agreement. Any allocation made pursuant to this Section 6.1(d)(xi)(A) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xi) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

 

(B)   In the case of any negative adjustments to the Capital Accounts of the Members resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the Board of Directors, that to the extent possible the aggregate Capital Accounts of the Members will equal the amount that would have been the Capital Account balance of the Members if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

 

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(C)   In making the allocations required under this Section 6.1(d)(xi), the Board of Directors may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xi).

Section 6.2    Allocations for Tax Purposes.

 

(a)   Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Members in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

 

(b)   The deduction for depletion with respect to each separate oil and gas property (as defined in Section 614 of the Code) shall be computed for federal income tax purposes separately by the Members rather than by the Company in accordance with Section 613A(c)(7)(D) of the Code. Except as provided in Section 6.2(c)(iii)), for purposes of such computation (before taking into account any adjustments resulting from an election made by the Company under Section 754 of the Code), the adjusted tax basis of each oil and gas property (as defined in Section 614 of the Code) shall be allocated among the Members in accordance with their respective Percentage Interests.

Each Member shall separately keep records of his share of the adjusted tax basis in each oil and gas property, allocated as provided above, adjust such share of the adjusted tax basis for any cost or percentage depletion allowable with respect to such property, and use such adjusted tax basis in the computation of its cost depletion or in the computation of his gain or loss on the disposition of such property by the Company.

 

(c)   Except as provided in Section 6.2(c)(iii), for the purposes of the separate computation of gain or loss by each Member on the sale or disposition of each separate oil and gas property (as defined in Section 614 of the Code), the Company’s allocable share of the “amount realized” (as such term is defined in Section 1001(b) of the Code) from such sale or disposition shall be allocated for federal income tax purposes among the Members as follows:

 

  (i)   first, to the extent such amount realized constitutes a recovery of the Simulated Basis of the property, to the Members in the same proportion as the depletable basis of such property was allocated to the Members pursuant to Section 6.2(b) (without regard to any special allocation of basis under Section 6.2(c)(iii));

 

  (ii)   second, the remainder of such amount realized, if any, to the Members so that, to the maximum extent possible, the amount realized allocated to each Member under this Section 6.2(c)(ii) will equal such Member’s share of the Simulated Gain recognized by the Company from such sale or disposition.

 

  (iii)   The Members recognize that with respect to Contributed Property and Adjusted Property there will be a difference between the Carrying Value of such property at the time of contribution or revaluation, as the case may be, and the adjusted tax basis of such property at that time. All items of tax depreciation, cost recovery, amortization, adjusted tax basis of depletable properties, amount realized and gain or loss with respect to such Contributed Property and Adjusted Property shall be allocated among the Members to take into account the disparities between the Carrying Values and the adjusted tax basis with respect to such properties in accordance with the principles of Treasury Regulation Section 1.704-3(d) except as otherwise determined by the Board of Directors with respect to goodwill.

 

  (iv)   Any elections or other decisions relating to such allocations shall be made by the Board of Directors in any manner that reasonably reflects the purpose and intention of the Agreement.

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(d)   In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, other than an oil and gas property pursuant to Section 6.2(c), items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Members as follows:

 

  (i)   (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Members in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

 

  (ii)   (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Members in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.4(c)(i) or Section 5.4(c)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Members in a manner consistent with Section 6.2(d)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Members in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

 

  (iii)   The Board of Directors shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities except as otherwise determined by the Board of Directors with respect to goodwill.

 

(e)   For the proper administration of the Company and for the preservation of uniformity of the Common Units (or any class or classes thereof), the Board of Directors shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Common Units (or any class or classes thereof). The Board of Directors may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(e) only if such conventions, allocations or amendments would not have a material adverse effect on the Members, the holders of any class or classes of Common Units issued and Outstanding or the Company, and if such allocations are consistent with the principles of Section 704 of the Code.

 

(f)   The Board of Directors may not determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) or to depreciate or amortize such portion of an adjustment using a predetermined rate derived from the depreciation or amortization method and useful life applied to the Company’s common basis of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6), Treasury Regulation Section 1.197-2(g)(3), the legislative history of Section 743 of the Code or any successor regulations thereto. If the Board of Directors determines that such reporting position cannot be taken, the Board of Directors may adopt depreciation and amortization conventions under which all purchasers acquiring Common Units in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Company’s property. If the Board of Directors chooses not to utilize such aggregate method, the Board of Directors may use any other depreciation and amortization conventions to preserve the

 

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uniformity of the intrinsic tax characteristics of any Member Interests, so long as such conventions would not have a material adverse effect on the Members or the Record Holders of any class or classes of Common Units.

 

(g)   Any gain allocated to the Members upon the sale or other taxable disposition of any Company asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Members (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

 

(h)   All items of income, gain, loss, deduction and credit recognized by the Company for federal income tax purposes and allocated to the Members in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Company; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the Board of Directors) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

 

(i)   Each item of Company income, gain, loss and deduction shall, for federal income tax purposes, be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Members as of the opening of the National Securities Exchange on which the Common Units are then traded on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the Option Closing Date or the expiration of the Over-Allotment Option occurs shall be allocated to the Members as of the opening of the National Securities Exchange on which the Common Units are then traded on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Company or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the Board of Directors, shall be allocated to the Members as of the opening of the National Securities Exchange on which the Common Units are then traded on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The Board of Directors may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

 

(j)   Allocations that would otherwise be made to a Member under the provisions of this Article 6 shall instead be made to the beneficial owner of Common Units held by a nominee in any case in which the nominee has furnished the identity of such owner to the Company in accordance with Section 6031(c) of the Code or any other method determined by the Board of Directors.

Section 6.3    Requirement and Characterization of Distributions; Distributions to Record Holders.

 

(a)   Within 45 days following the end of each Quarter commencing with the Quarter ending on December 31, 2006, an amount equal to 100% of Available Cash with respect to such Quarter shall, subject to Section 18-607 of the Delaware Act, be distributed in accordance with this Article 6 by the Company to the Members as of the Record Date selected by our Board of Directors for such distribution (or by an Officer designated by our Board of Directors to select the Record Date for such distribution). All amounts of Available Cash distributed by the Company on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Company to the Members pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the date of determination. Any remaining amounts of Available Cash distributed by the Company on such date shall, except as otherwise provided in Section 6.4, be deemed to be Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Section 18-607 or Section 18-804 of the Delaware Act.

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(b)   Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Company, all receipts received during or after the Quarter in which the Liquidation Date occurs shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 10.3.

 

(c)   The Company may treat taxes paid by the Company on behalf of, or amounts withheld with respect to, all or less than all of the Members, as a distribution of Available Cash to such Members.

 

(d)   Each distribution in respect of a Member Interest shall be paid by the Company, directly or through the Transfer Agent or through any other Person or agent, only to the Record Holder of such Member Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Company’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4    Distributions of Available Cash from Operating Surplus.

 

(a)   During the MII Vesting Period. Available Cash with respect to any Quarter ending prior to or on the date of the end of the MII Vesting Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.6 shall, subject to Section 18-607 of the Delaware Act, be distributed, except as otherwise required by Section 5.5(b) in respect of other Company Securities issued pursuant thereto, as follows: (A) 2% to the holder(s) of the Class A Units, Pro Rata and (B) 98% to the holders of the Common Units, Pro Rata.

 

(b)   After the MII Vesting Period. Available Cash with respect to each Quarter after the MII Vesting Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.6 shall, subject to Section 18-607 of the Delaware Act, be distributed, except as otherwise required by Section 5.5(b) in respect of additional Company Securities issued pursuant thereto, as follows:

 

  (i)   First, (A) 2% to the holders of the Class A Units, Pro Rata, and (B) 98% to the holders of Common Units, Pro Rata, until there has been distributed in respect of each Class A Unit and each Common Unit then Outstanding an amount equal to the Initial Quarterly Distribution for such Quarter;

 

  (ii)   Second, (A) 2% to the holders of Class A Units, Pro Rata, and (B) 98% to the holders of Common Units, Pro Rata, until there has been distributed in respect of each Class A Unit and each Common Unit then Outstanding an amount equal to the Initial Quarterly Distribution for such Quarter plus $0.06 (the “First Target Distribution”);

 

  (iii)   Third, (A) 2% to the holders of the Class A Units, Pro Rata, (B) 83% to the holders of the Common Units, Pro Rata, and (C) 15% to the holders of the Management Incentive Interests, Pro Rata, until there has been distributed in respect of each Class A Unit and each Common Unit then Outstanding an amount equal to the Initial Quarterly Distribution for such Quarter plus $0.17 (the “Second Target Distribution”); and

 

  (iv)   Thereafter, (A) 2% to the holders of the Class A Units, Pro Rata, (B) 73% to the holders of the Common Units, Pro Rata, and (C) 25% to the holders of the Management Incentive Interests, Pro Rata.

Section 6.5    Payment of the EP MID.

If both the 12-Quarter Test and the 4-Quarter Test have been met with respect to the Incentive Trigger Period, an EP MID shall be made contemporaneously with the distribution paid in respect of the Class A Units and Common Units pursuant to Section 6.4 for the fourth calendar quarter in the 4-Quarter Test to the holder of the Management Incentive Interests.

 


 

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Section 6.6    Distributions of Available Cash from Capital Surplus.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall, subject to Section 18-607 of the Delaware Act, be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the holders of Common Units, Pro Rata, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Issue Price. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.7    Adjustment of Initial Quarterly Distribution, First Target Distribution, Second Target Distribution and Unrecovered Capital.

 

(a)   The Initial Quarterly Distribution, First Target Distribution, Second Target Distribution and Unrecovered Capital shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Company Securities in accordance with Section 5.8. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Initial Quarterly Distribution, First Target Distribution and Second Target Distribution shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Initial Quarterly Distribution, First Target Distribution and Second Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Capital of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Capital of the Common Units immediately prior to giving effect to such distribution.

 

(b)   The Initial Quarterly Distribution, First Target Distribution and Second Target Distribution shall also be subject to adjustment pursuant to Section 6.8.

Section 6.8    Entity-Level Taxation.

If legislation is enacted or the interpretation of existing language is modified by a governmental taxing authority so that a Company Group member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the Board of Directors may reduce the Initial Quarterly Distribution, the First Target Distribution and the Second Target Distribution by the amount of the income taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Tax”), or any portion thereof selected by the Board of Directors, in the manner provided in this Section 6.8. If the Board of Directors elects to reduce the Initial Quarterly Distribution, the First Target Distribution and the Second Target Distribution for any Quarter with respect to all or a portion of the Incremental Income Taxes, the Board of Directors shall estimate for such Quarter the Company Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all (or the relevant portion of) such Incremental Income Taxes; provided that any difference between such estimate and the actual liability for Incremental Income Taxes (or the relevant portion thereof) for such Quarter may, to the extent determined by the Board of Directors, be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Initial Quarterly Distribution shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.8 times (b) the quotient obtained by dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the Board of Directors. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.


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Article 7

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1    Board of Directors.

 

(a)   Except as otherwise expressly provided in this Agreement, the business and affairs of the Company shall be managed by or under the direction of a Board of Directors (the “Board of Directors”). As provided in Section 7.4, the Board of Directors shall have the power and authority to appoint Officers of the Company. The Directors shall constitute “managers” within the meaning of the Delaware Act. No Member, by virtue of its status as such, shall have any management power over the business and affairs of the Company or actual or apparent, authority to enter into, execute or deliver contracts on behalf of, or to otherwise bind, the Company. Except as otherwise specifically provided in this Agreement, the authority and functions of the Board of Directors, on the one hand, and of the Officers, on the other, shall be identical to the authority and functions of the board of directors and officers, respectively, of a corporation organized under the DGCL. In addition to the powers that now or hereafter can be granted to managers under the Delaware Act and to all other powers granted under any other provision of this Agreement, subject to Section 7.3, the Board of Directors shall have full power and authority to do, and to direct the Officers to do, all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Company, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

 

  (i)   the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into Company Securities, and the incurring of any other obligations;

 

  (ii)   the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Company;

 

  (iii)   the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Company or the merger or other combination of the Company with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 and Article 12);

 

  (iv)   the use of the assets of the Company (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Company Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of the Company Group; and the making of capital contributions to any member of the Company Group;

 

  (v)   the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Company under contractual arrangements to all or particular assets of the Company);

 

  (vi)   the distribution of Company cash;

 

  (vii)   the selection and dismissal of Officers, employees, agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring, the creation and operation of employee benefit plans, employee programs and employee practices;

 

  (viii)   the maintenance of insurance for the benefit of the Company Group, the Members and any Indemnitees;

 

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  (ix)   the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

 

  (x)   the control of any matters affecting the rights and obligations of the Company, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation, and the incurring of legal expense and the settlement of claims and litigation;

 

  (xi)   the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

 

  (xii)   the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Member Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.6);

 

  (xiii)   the purchase, sale or other acquisition or disposition of Company Securities, or the issuance of options, rights, warrants and appreciation rights relating to Company Securities;

 

  (xiv)   the undertaking of any action in connection with the Company’s participation in any Group Member; and

 

  (xv)   the entering into of agreements with any of its Affiliates to render services to a Group Member.

 

(b)   The Board of Directors shall consist of 7 natural Persons. Each Director shall be elected as provided in Section 7.1(c) and shall serve in such capacity until his or her successor has been duly elected and qualified or until such Director dies, resigns or is removed. A Director may resign at any time upon written notice to the Company. The Board of Directors may from time to time determine the number of Directors then constituting the whole Board of Directors, but the Board of Directors shall not decrease the number of Persons that constitute the whole Board of Directors if such decrease would shorten the term of any Director.

 

(c)   The persons comprising the initial Board of Directors shall be as follows: Edward E. Cohen, Jonathan Z. Cohen, Richard D. Weber, Matthew A. Jones, Walter C. Jones, Ellen F. Warren and Bruce M. Wolf. Such persons shall serve as members of the Board of Directors until the annual meeting of Members to be held in 2007 and until their successors are duly elected and qualified, or until their earlier death, resignation or removal. After the closing of the Initial Offering, the Directors shall be elected at each annual meeting of Members to serve for a term expiring at the next annual meeting of Members. The nomination of Persons to serve as Directors and the election of the Board of Directors shall be in accordance with Article 11.

 

(d)   Any Director may be removed at any time, with or without cause, only by the affirmative vote or consent of a Unit Majority.

 

(e)   Subject to the rights of the holders of any series of Member Interests, 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 Members and until his or her successor has been duly elected and qualified or until such Director’s earlier death, resignation or removal.

 

(f)   Directors need not be Members. The Board of Directors may, from time to time and by the adoption of resolutions, establish qualifications for Director.

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(g)   Unless otherwise required by the Delaware Act, other law or the provisions hereof,

 

  (i)   each member of the Board of Directors shall have one vote;

 

  (ii)   the presence at a meeting of the Board of Directors of a majority of the members of the Board of Directors shall constitute a quorum at any such meeting for the transaction of business; and

 

  (iii)    the act of a majority of the members of the Board of Directors present at a meeting of the Board of Directors at which a quorum is present shall be deemed to constitute the act of the Board of Directors.

 

(h)   Regular meetings of the Board of Directors and any committee thereof shall be held at such times and places as shall be designated from time to time by resolution of the Board of Directors or such committee. Notice of such regular meetings shall not be required. Special meetings of the Board of Directors or meetings of any committee thereof may be called by the Chairman of the Board or on written request of a majority of the Directors or the committee members to the Secretary, in each case on at least 24 hours personal, written, facsimile, electronic or telephonic notice to each Director or committee member, which notice may be waived by any Director. Any such notice, or waiver thereof, need not state the purpose of such meeting except as may otherwise be required by law. Attendance of a Director at a meeting (including pursuant to the last sentence of this Section 7.1(h)) shall constitute a waiver of notice of such meeting, except where such Director attends the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened. Any action required or permitted to be taken at a meeting of the Board of Directors, or any committee thereof, may be taken without a meeting, without prior notice and without a vote if a consent in writing, setting forth the action so taken, is signed by all members of the Board of Directors or committee. Members of the Board of Directors or any committee thereof may participate in and hold a meeting by means of conference telephone, video conference or similar communications equipment by means of which all Persons participating in the meeting can hear each other, and participation in such meetings shall constitute presence in person at the meeting.

 

(i)    (i)   The Board of Directors shall have the following committees:

 

  (A)   A Conflicts Committee which shall have the responsibilities set forth in Section 7.9.

 

  (B)   An Audit Committee which shall have the power and authority to select the Company’s independent auditors, review the scope and results of all audits and review the adequacy of the Company’s accounting, financial and operating controls.

 

  (ii)   The Board of Directors may, by resolution of a majority of the full Board of Directors, designate one or more other committees, each committee to consist of one or more of the Directors, and the Board of Directors may from time to time adopt a charter for any of such committees.

 

  (iii)   The Board of Directors may designate one or more Directors as alternate members of any committee, who may replace any absent or disqualified Director at any meeting of such committee.

 

  (iv)   Any such committee, to the extent provided in the resolution of the Board of Directors or in this Agreement, shall have and may exercise all powers and authority of the Board of Directors in the management of the business and affairs of the Company; but no such committee shall have the power or authority in reference to the following matters: approving or adopting, or recommending to the Members, any action or matter expressly required by this Agreement or the Delaware Act to be submitted to the Members for approval, or adopting, amending or repealing any provision of this Agreement. Unless specified by resolution of the Board of

 

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Directors, any committee designated pursuant to this Section 7.1(i) shall choose its own chairman, shall keep regular minutes of its proceedings and report the same to the Board of Directors when requested, and, subject to Section 7.1(h), shall fix its own rules or procedures and shall meet at such times and at such place or places as may be provided by such rules. At every meeting of any such committee, the presence of a majority of all the members thereof shall constitute a quorum and the affirmative vote of a majority of the members present at a meeting of which a quorum is present shall be necessary for the adoption by the committee of any resolution.

 

(j)   Unless otherwise restricted by law, the Board of Directors shall have the authority to fix the compensation of the Directors. The Directors may be paid their expenses, if any, of attendance at each meeting of the Board of Directors and may be paid a fixed sum for attendance at each meeting of the Board of Directors or, with respect to Directors who are not Officers, or officers or employees of Atlas Energy Management or any of its Affiliates, paid a stated salary or paid other compensation as Director. No such payment shall preclude any Director from serving the Company in any other capacity and receiving compensation therefor. Members of special or standing committees may also be paid their expenses, if any, of and allowed compensation for attending committee meetings.

 

(k)   Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Members and each other Person
  who may acquire an interest in Company Securities hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Management Agreement, the Omnibus Agreement, the Contribution Agreement, the APL Omnibus Agreement Amendment, the Gas Gathering Agreements Amendment, the Services Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement; (ii) agrees that the Board of Directors (on its own or through any Officer) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Company without any further act, approval or vote of the Members or the other Persons who may acquire an interest in Company Securities; and (iii) agrees that the execution, delivery or performance by the Company, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement shall not constitute a breach by the Board of Directors or any Officer of any duty that the Board of Directors or any Officer may owe the Company or the Members or any other Persons under this Agreement (or any other agreements) or of any duty existing at law, in equity or otherwise.

 

(l)   The Board of Directors shall have the right, in respect to any of its powers or obligations hereunder, to act through a duly appointed attorney or attorneys-in-fact or the duly authorized Officers.

Section 7.2    Certificate of Formation.

The Certificate of Formation has been filed with the Secretary of State of the State of Delaware as required by the Delaware Act, such filing being hereby confirmed, ratified and approved in all respects. The Board of Directors shall use all reasonable efforts to cause to be filed such other certificates or documents that it determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited liability company in the State of Delaware or any other state in which the Company may elect to do business or own property. To the extent that the Board of Directors determines such action to be necessary or appropriate, the Board of Directors shall direct the appropriate Officers to file amendments to and restatements of the Certificate of Formation and do all things to maintain the Company as a limited liability company under the laws of the State of Delaware or of any


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other state in which the Company may elect to do business or own property and any such Officer so directed shall be an “authorized person” of the Company within the meaning of the Delaware Act for purposes of filing any such certificate with the Secretary of State of the State of Delaware. The Company shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Formation, any qualification document or any amendment thereto to any Member.

Section 7.3    Restrictions on the Board of Directors’ Authority.

 

(a)   Except as otherwise provided in this Agreement, the Board of Directors may not, without written approval of the specific act by holders of all of the Outstanding Member Interests or by other written instrument executed and delivered by holders of all of the Outstanding Member Interests subsequent to the date of this Agreement, take any action that is in breach or violation of this Agreement.

 

(b)   Except as provided in Article 10 and Article 12, the Board of Directors may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Company Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Company’s Subsidiaries) without the approval of holders of a Class A Unit Majority and a Common Unit Majority; provided, however, that this provision shall not preclude or limit the Board of Directors’ ability to mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the assets of the Company Group and shall not apply to any forced sale of any or all of the assets of the Company Group pursuant to the foreclosure of, or other realization upon, any such encumbrance.

Section 7.4    Officers.

 

(a)   The Board shall appoint Officers as described in this Section 7.4, who shall be responsible for the day-to-day business affairs of the Company, subject to the overall direction and control of the Board. Unless provided otherwise by the Board, the Officers shall have the titles, power, authority and duties described below.

 

(b)   The Officers shall be the Chairman of the Board, the Vice Chairman, the Chief Executive Officer, the President, any and all Vice Presidents, the Chief Operating Officer, the Chief Financial Officer, the Secretary and any other Officers appointed pursuant to this Section 7.4. Any Person may hold two or more offices.

 

  (i)   Chairman of the Board.    The Chairman of the Board shall, if present, preside at meetings of the Board and exercise and perform such other powers and duties as may from time to time be assigned by the Board or as may be prescribed by this Agreement.

 

  (ii)   Vice Chairman of the Board.    The Vice Chairman of the Board shall preside at all meetings of the Board in the absence of the Chairman of the Board. In the absence or disability of the Chairman of the Board, or in the event that it is impractical for the Chairman of the Board to act personally, the Vice Chairman of the Board shall have the powers and duties of the Chairman of the Board. The Vice Chairman of the Board shall also have such other powers or duties as shall be assigned by the Board or as may be prescribed by this Agreement.

 

  (iii)   Chief Executive Officer.    The Chief Executive Officer shall have general supervision, direction and control of the business and the Officers of the Company. In the absence or nonexistence of a Chairman of the Board or Vice Chairman of the Board, the Chief Executive Officer shall preside at meetings of the Board. The Chief Executive Officer shall also have such other powers and duties as may be assigned by the Board or as may be prescribed by this Agreement.

 

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  (iv)   President.    The President shall have such powers and perform such duties as may be assigned by the Board or by the Chairman of the Board. In the absence or disability of the President, his or her duties shall be performed by such Vice Presidents as the Chairman of the Board or the Board may designate. The President shall report to the Chief Executive Officer.

 

  (v)   Vice Presidents.    In the absence or disability of the President, the Vice Presidents, if any, in order of their rank as fixed by the Board or, if not ranked, a Vice President designated by the Board, shall perform all the duties of the President and when so acting shall have all the powers of, and be subject to all the restrictions upon, the President. The Vice Presidents shall have such other powers and perform such other duties as from time to time may be prescribed for them respectively by the Board, the Chairman of the Board or the President. The Board may designate one or more Vice Presidents as Executive Vice President, Senior Vice President or as Vice President for particular areas of responsibility.

 

  (vi)   Chief Operating Officer.    The Chief Operating Officer shall supervise the property and ongoing business and affairs of the Company, under the direction of the Chief Executive Officer, in accordance with the policies established by the Board and subject to overall discretion, authority and responsibility of the Board. The Chief Operating Officer shall report to the Chief Executive Officer.

 

  (vii)   Chief Financial Officer.    The Chief Financial Officer shall have general supervision over the financial affairs of the Company, including but not limited to, oversight of capital formation and financial transactions associated therewith, oversight of capital allocation, establishment of corporate budgets, oversight of corporate accounting procedures, maintenance of adequate and correct books and records of accounts of the properties and business transactions of the Company and oversight of investor relations. The Chief Financial Officer shall report to the Chief Executive Officer.

 

  (viii)   Secretary.    The Secretary shall keep or cause to be kept, at the principal executive office of the Company or such other place as the Board may direct, a book of minutes of all meetings and actions of the Board and committees. The Secretary shall cause to be kept such books and records as the affairs of the business may require and the Board, the Chairman or the President may require. The Secretary shall attend to such correspondence and such other duties as may be incident to the office of the Secretary. The Secretary shall give, or cause to be given, notice of all meetings of the Board required to be given by law or by this Agreement. The Secretary shall keep the seal of the Company, if one be adopted, in safe custody and shall have such other powers and perform such other duties as may be assigned by the Board or as may be prescribed by this Agreement.

 

(c)   The Board may appoint such other Officers and agents as may from time to time appear to be necessary or advisable in the conduct of the affairs of the Company, who shall hold their offices for such terms and shall exercise such powers and perform such duties as shall be determined from time to time by the Board.

 

(d)   The Officers shall be appointed by the Board at such time and for such terms as the Board shall determine. Any Officer may be removed, with or without cause, only by the Board. Vacancies in any office may be filled only by the Board.

 

(e)   The Board may grant powers of attorney or other authority as appropriate to establish and evidence the authority of the Officers and other Persons.

 

(f)   Unless otherwise provided by resolution of the Board, no Officer shall have the power or authority to delegate to any Person such Officer’s rights and powers as an Officer to manage the business and affairs of the Company.

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(g)   The Officers shall receive such compensation for their services as may be designated by the Board.

Section 7.5    Outside Activities.

 

(a)   Except as specifically provided in the Omnibus Agreement and the Management Agreement, it shall be deemed not to be a breach of any duty (including any fiduciary duty) existing hereunder, at law or in equity, or any other obligation of any type whatsoever of (i) any Director or Officer, or any Affiliate of any of them to engage in outside business interests and activities in preference to or to the exclusion of the Company or in direct competition with the Company; provided such Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Company to such Person and that the Board of Directors is advised of such other relationship and does not object thereto.

 

(b)   Except as specifically provided in the Omnibus Agreement and the Management Agreement, none of the Directors or Officer, shall have any obligation hereunder or as a result of any duty expressed or implied by law or in equity to present business opportunities to the Company that may become available to Affiliates or such Person or of which the Person acquires knowledge other than while serving in the capacity as a Director or Officer. Except as specifically provided in the Omnibus Agreement, none of any Group Member, any Member or any other Person shall have any rights by virtue of a Person’s duties under this Agreement, any Group Member Agreement, the Management Agreement, applicable law or otherwise in any business ventures of any Person.

 

(c)   Notwithstanding anything to the contrary in this Agreement, to the extent that any provisions of this Section 7.5 purport or are interpreted to have the effect of restricting, eliminating or otherwise modifying the duties (including fiduciary duties) that might otherwise, as a result of Delaware or other applicable law, be owed by the Directors, the Officers or any of their Affiliates to the Company and its Members, or to constitute a waiver or consent by the Members to any such fiduciary duty, such provisions in this Section 7.5 shall be deemed to have been approved by the Members, and the Members hereby agree that such provisions shall replace or eliminate such duties.

Section 7.6    Loans or Contributions from the Company or Group Members.

 

(a)   The Company may lend or contribute to any Group Member, and any Group Member may borrow from the Company, funds on terms and conditions determined by the Board of Directors.

 

(b)   No borrowing by any Group Member or the approval thereof by the Board of Directors shall be deemed to constitute a breach of any duty (including any fiduciary duty), hereunder or existing at law, in equity or otherwise, of the Board of Directors to the Company or the Members by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to enable distributions to the Members.

Section 7.7    Indemnification.

 

(a)   To the fullest extent permitted by law as it currently exists and to such greater extent as applicable law hereafter may permit, but subject to the limitations expressly provided in this Agreement, the Company shall indemnify, hold harmless and defend 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, any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (including an action by or in the right of the Company) by reason of the fact that such Person is an Indemnitee or by reason of any action alleged to have been taken or omitted in such capacity, against losses, expenses (including attorneys’ fees of counsel for such Indemnitee), judgments, fines, damages, penalties, interest, liabilities and amounts paid in settlement

 

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actually and reasonably incurred by the Person in connection with such action, suit or proceeding; provided, that the Indemnitee shall 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 pursuant to this Section 7.7(a), the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful. The termination of any action, suit or proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the Person acted in bad faith or engaged in fraud, willful misconduct or, with respect to any criminal action or proceeding, acted with the knowledge that the Person’s conduct was unlawful.

 

(b)   To the extent an Indemnitee has been successful on the merits or otherwise in defense of any action, suit or proceeding referred to in Section 7.7(a), or in the defense of any claim, issue or matter therein, such Person shall be indemnified against expenses (including attorneys’ fees) actually and reasonably incurred by such Person in connection therewith.

 

(c)   Expenses (including reasonable attorneys’ fees of counsel for such Indemnitee) incurred by an Indemnitee in defending any action, suit or proceeding referred to in Section 7.7(a) shall be paid by the Company, when and as incurred, in advance of the final disposition of such action, suit or proceeding and in advance of any determination that such Indemnitee is not entitled to be indemnified, upon receipt of an undertaking by or on behalf of such Indemnitee to repay such amount if it shall ultimately be determined by final judicial decision from which there is no further right to appeal (a “Final Adjudication”) that such Person is not entitled to be indemnified by the Company as authorized in this Section 7.7.

 

(d)   The indemnification, advancement of expenses and other provisions of this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Member Interests, as a matter of law or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

 

(e)   The Company may purchase and maintain insurance, on behalf of its Directors and Officers, and such other Persons as the Board of Directors shall determine, against any liability that may be asserted against or expense that may be incurred by such Person in connection with the Company’s activities or such Person’s activities on behalf of the Company, regardless of whether the Company would have the power to indemnify such Person against such liability under the provisions of this Agreement.

 

(f)   For purposes of the definition of Indemnitee in Section 1.1, the Company shall be deemed to have requested a Person to serve as fiduciary of an employee benefit plan whenever the performance by such Person of his duties to the Company also imposes duties on, or otherwise involves services by, such Person to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by such Person with respect to any employee benefit plan in the performance of such Person’s duties for a purpose reasonably believed by him to be in the interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in, or not opposed to, the best interests of the Company.

 

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and shall have no obligation to contribute or loan any monies or property to the Company to enable it to effectuate such indemnification.

 

(h)   An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

 

(i)   If a claim under Section 7.7 is not paid in full by the Company within 60 days after a written claim has been received by the Company, except in the case of a claim for an advancement of expenses, in which case the applicable period shall be 20 days, the Indemnitee may at any time thereafter bring suit against the Company to recover the unpaid amount of the claim. If successful in whole or in part in any such suit, or in a suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Indemnitee shall be entitled to be paid also the reasonable expenses of prosecuting or defending such suit. In (i) any suit brought by the Indemnitee to enforce a right to indemnification hereunder (but not in a suit brought by the Indemnitee to enforce a right to an advancement of expenses) it shall be a defense that, and (ii) in any suit brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the Company shall be entitled to recover such expenses upon a Final Adjudication that, the Indemnitee has not met any applicable standard for indemnification set forth in this Agreement. Neither the failure of the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) to have made a determination prior to the commencement of such suit that indemnification of the Indemnitee is proper in the circumstances because the Indemnitee has met the applicable standard of conduct set forth in this Agreement, nor an actual determination by the Company (including its Directors who are not parties to such action, a committee of such Directors, independent legal counsel, or its Members) that the Indemnitee has not met the applicable standard of conduct shall create a presumption that the Indemnitee has not met the applicable standard of conduct, or, in the case of such a suit brought by the Indemnitee, be a defense to such suit. In any suit brought by the Indemnitee to enforce a right to indemnification or to an advancement of expenses hereunder, or brought by the Company to recover an advancement of expenses pursuant to the terms of an undertaking, the burden of proving that the Indemnitee is not entitled to be indemnified or to such advancement of expenses, under this Section 7.7 or otherwise shall be on the Company.

 

(j)   The Company may 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 (whether or not an action by or in the right of the Company) by reason of the fact that the Person is or was an employee (other than an Officer) or agent of the Company, or, while serving as an employee (other than an Officer) or agent of the Company is or was serving at the request of the Company as a manager, director, officer, employee, partner, fiduciary, trustee or agent of another Group Member or another Person to the extent

 

  (i)   permitted by the laws of the State of Delaware as from time to time in effect, and

 

  (ii)   authorized by the Board of Directors.

The Company may, to the extent permitted by Delaware law and authorized by the Board of Directors, pay expenses (including attorneys’ fees) reasonably incurred by any such employee or agent in defending any civil, criminal, administrative or investigative action, suit or proceeding in advance of the final disposition of such action, suit or proceeding, upon such terms and conditions as the Board of Directors determine. The provisions of this Section 7.7(j) shall not constitute a contract right for any such employee or agent.


 

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(k)   The indemnification, advancement of expenses and other provisions of this Section 7.7 are for the benefit of the Indemnitees, their heirs, successors, assigns and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

 

(l)   Except to the extent otherwise provided in Section 7.7(j), the right to be indemnified and to receive advancement of expenses in this Section 7.7 shall be a contract right. No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Company, nor the obligations of the Company to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8    Exculpation of Liability of Indemnitees.

 

(a)   Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable to the Company, the Members or any other Persons who have acquired interests in Company Securities for losses sustained or liabilities 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, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

 

(b)   Subject to its obligations and duties as Board of Directors set forth in this Article 7, the Board of Directors may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the Board of Directors shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the Board of Directors in good faith.

 

(c)   To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Company, to the Members or any other Persons who have acquired interests in Company Securities, none of the Directors and any other Indemnitee acting in connection with the Company’s business or affairs shall be liable to the Company, to any Member or any other Persons who have acquired interests in Company Securities for its good faith reliance
  on the provisions of this Agreement. The provisions of this Agreement, to the extent that they restrict or eliminate or otherwise modify the duties (including fiduciary duties) and liabilities of an Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of such Indemnitee.

 

(d)   Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of any Indemnitee under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

 

(e)   An Indemnitee shall be fully protected in relying in good faith upon the records of the Company and upon information, opinions, reports or statements presented by a Director, Member or liquidating trustee, an Officer or employee of the Company, or committees of the Company, Members or Directors, or by any other person as to matters that the Member, Director or liquidating trustees reasonably believes are within such other Person’s professional or expert competence, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, profits or losses of the Company, or the value and amount of assets or reserves or contracts, agreements or other undertakings that would be sufficient to pay claims and obligations of the

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Company or to make reasonable provision to pay such claims and obligations, or any other facts pertinent to the existence and amount of assets from which distributions to members or creditors might properly be paid.

Section 7.9    Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

 

(a)   Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between any Affiliate of the Company, on the one hand, and the Company or any Group Member, on the other, any resolution or course of action by the Board of Directors in respect of such conflict of interest shall be permitted and deemed approved by all Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of holders of a majority of the Outstanding Common Units (excluding Common Units held by interested parties), (iii) on terms no less favorable to the Company than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Company, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Company). The Board of Directors shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval of such resolution, and the Board of Directors may also adopt a resolution or course of action that has not received Special Approval, provided that interested directors shall recuse themselves from participation in such resolution. If Special Approval is not sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest complies with the standards set forth in clause (iii) or (iv) of the second preceding sentence, then (A) such resolution or course of action shall be permitted and deemed approved by all the Members, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty existing at law, in equity or otherwise, including any fiduciary duty and (B) it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Member or Assignee or by or on behalf of such Member or any other Member or the Company challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Members and shall not constitute a breach of this Agreement or any duty existing at law, in equity or otherwise.

 

(b)   Whenever the Board of Directors or any Director or Officer makes a determination or takes or declines to take any other action, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the Board of Directors or such Director or Officer shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take other action must believe that the determination or other action is in the best interests of the Company. No action taken by the Board of Directors, any Director or any Officer on behalf of the Company in good faith reliance on the provisions of this Agreement, including this Article 7, shall constitute a breach of any duty (including any fiduciary duty or other similar duty) on the part of such Board of Directors or any Director or Officer, as the case may be. To the extent that the foregoing provisions have, or are construed to have, the effect of restricting, eliminating or otherwise

 

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modifying the duties and liabilities, including fiduciary duties, of the Directors or Officers otherwise existing at law, in equity or otherwise, such provisions and any such restriction, elimination or modification (i) are, and shall be deemed to have been, approved and agreed to by the Members (ii) are intended and agreed to replace and supersede such other duties and liabilities.

 

(c)   Notwithstanding anything to the contrary in this Agreement prior to the dissolution of the Company, the Board of Directors shall have no duty or obligation, express or implied, to sell or otherwise dispose of any asset of the Company Group other than in the ordinary course of business.

 

(d)   Except as expressly set forth in this Agreement or required by law, none of the Directors, nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Company or any Member and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the Directors or any other Indemnitee otherwise existing at law or in equity, are agreed by the Members to replace such other duties and liabilities of the Directors or such other Indemnitee.

 

(e)   The Members hereby authorize the Board of Directors, on behalf of the Company as a partner or member of a Group Member, to approve of actions by the Board of Directors or managing member of such Group Member similar to those actions permitted to be taken by the Board of Directors pursuant to this Section 7.9.

Section 7.10    Duties of Officers and Directors

 

(a)   The duties and obligations owed to the Company and to the Members by the Officers and Directors shall be as set forth in this Agreement.

 

(b)   A Director shall, in the performance of his duties, be fully protected in relying in good faith upon the records of the Company and on such information, opinions, reports or statements presented to the Company by any of the Company’s Officers or employees, or committees of the Board of Directors, or by any other Person as to matters the Director reasonably believes are within such other Person’s professional or expert competence and who has been selected with reasonable care by or on behalf of the Company.

 

(c)   The Board of Directors shall have the right, in respect of any of its powers or obligations hereunder, to act through a duly appointed attorney or attorneys-in-fact or the duly authorized Officers of the Company.

Section 7.11    Purchase or Sale of Company Securities.

The Board of Directors may cause the Company to purchase or otherwise acquire Company Securities.

Section 7.12    Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Company shall be entitled to assume that the Board of Directors and any Officer authorized by the Board of Directors to act on behalf of and in the name of the Company has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Company and to enter into any authorized contracts on behalf of the Company, and such Person shall be entitled to deal with the Board of Directors or any Officer as if it were the Company’s sole party in interest, both legally and beneficially. Each Member hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the Board of Directors or any Officer in connection with any such dealing. In no event shall any Person dealing with the Board of Directors or any Officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act


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or action of the Board of Directors or any Officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Company by the Board of Directors or any Officer or its representatives shall be conclusive evidence in favor of any and every Person relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Company and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Company.

Article 8

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1    Records and Accounting.

The Board of Directors shall keep or cause to be kept at the principal office of the Company appropriate books and records with respect to the Company’s business, including all books and records necessary to provide to the Members any information required to be provided pursuant to this Agreement. Any books and records maintained by or on behalf of the Company in the regular course of its business, including the record of the Record Holders or Assignees of Common Units or other Company Securities, books of account and records of Company proceedings, may be kept on, or be in the form of, computer disks, hard drives, punch cards, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Company shall be maintained, for financial reporting purposes, on an accrual accounting basis in accordance with U.S. GAAP.

Section 8.2    Fiscal Year.

The fiscal year of the Company shall be a fiscal year ending December 31, or such other date as determined by the Board of Directors.

Section 8.3    Reports.

 

(a)   As soon as practicable, but in no event later than 120 days after the close of each fiscal year of the Company, the Board of Directors shall cause to be mailed or made available by any reasonable means (including posting on the Company’s website) to each Record Holder of a Common Unit as of a date selected by the Board of Directors, an annual report containing financial statements of the Company for such fiscal year of the Company, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, equity and cash flows, such statements to be audited by a registered public accounting firm selected by the Board of Directors.

 

(b)   As soon as practicable, but in no event later than 90 days after the close of each Quarter except the last Quarter of each fiscal year, the Board of Directors shall cause to be mailed or made available to each Record Holder of a Common Unit, as of a date selected by the Board of Directors, a report containing unaudited financial statements of the Company and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Common Units are listed for trading, or as the Board of Directors determines to be necessary or appropriate.

 

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Article 9

TAX MATTERS

Section 9.1    Returns and Information.

The Company shall timely file all returns of the Company that are required for federal, state and local income tax purposes on the basis of the accrual method and a taxable year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable year shall be furnished to them within 90 days after the close of the calendar year in which the Company’s taxable year ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2    Tax Elections.

 

(a)   The Company shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the Board of Directors’ determination that such revocation is in the best interests of the Members. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the Board of Directors shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Member Interest will be deemed to be the lowest quoted closing price of the Member Interests on any National Securities Exchange on which such Member Interests are traded during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(c)(i) without regard to the actual price paid by such transferee.

 

(b)   The Company shall elect to amortize or deduct expenses incurred in organizing the Company as provided in Section 709 of the Code.

 

(c)   Except as otherwise provided herein, the Board of Directors shall determine whether the Company should make any other elections permitted by the Code.

Section 9.3    Tax Controversies.

Subject to the provisions hereof, the Board of Directors shall designate one Officer who is a Member as the Tax Matters Partner (as defined in the Code). The Tax Matters Partner is authorized and required to represent the Company (at the Company’s expense) in connection with all examinations of the Company’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Company funds for professional services and costs associated therewith. Each Member agrees to cooperate with the Tax Matters Partner and to do or refrain from doing any or all things reasonably required by the Tax Matters Partner to conduct such proceedings.

Section 9.4    Withholding.

Notwithstanding any other provision of this Agreement, the Board of Directors is authorized to take any action that may be required to cause the Company and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Company is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Member (including by reason of Section 1446 of the Code), the Board of Directors may treat the amount withheld as a distribution of cash pursuant to Section 6.3 in the amount of such withholding from such Member.


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Article 10

DISSOLUTION AND LIQUIDATION

Section 10.1    Dissolution.

The Company shall not be dissolved by the admission of Substituted Members or Additional Members. The Company shall dissolve, and its affairs shall be wound up, upon:

 

(a)   an election to dissolve the Company by the Board of Directors that is approved by the holders of a Class A Unit Majority and a Common Unit Majority;

 

(b)   the sale, exchange or other disposition of all or substantially all of the assets and properties of the Company Group;

 

(c)   the entry of a decree of judicial dissolution of the Company pursuant to the provisions of the Delaware Act; or

 

(d)   at such time as there are no Members, unless the Company is continued without dissolution in accordance with the Delaware Act.

Section 10.2    Liquidator.

Upon dissolution of the Company, the Board of Directors shall select one or more Persons to act as Liquidator. The Liquidator (if other than the Board of Directors) shall be entitled to receive such compensation for its services as may be approved by holders of a Unit Majority. The Liquidator (if other than the Board of Directors) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of a Unit Majority. Upon dissolution, death, incapacity, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of a Unit Majority. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly provided in this Article 10, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the Board of Directors under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3(b)) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Company as provided for herein.

Section 10.3    Liquidation.

The Liquidator shall proceed to dispose of the assets of the Company, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 18-804 of the Delaware Act and the following:

 

(a)   The assets may be disposed of by public or private sale or by distribution in kind to one or more Members on such terms as the Liquidator and such Member or Members may agree. If any property is distributed in kind, the Member receiving the property shall be deemed for purposes of Section 10.3(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Members. Notwithstanding anything to the contrary contained in this Agreement, the Members understand and acknowledge that a Member may be compelled to accept a distribution of any asset in kind from the Company

 

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despite the fact that the percentage of the asset distributed to such Member exceeds the percentage of that asset which is equal to the percentage in which such Member shares in distributions from the Company. The Liquidator may defer liquidation or distribution of the Company’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Company’s assets would be impractical or would cause undue loss to the Members. The Liquidator may distribute the Company’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Members.

 

(b)   Liabilities of the Company include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 10.2) and amounts to Members otherwise than in respect of their distribution rights under Article 6. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be applied to other liabilities or distributed as additional liquidation proceeds.

 

(c)   All property and all cash in excess of that required to discharge liabilities as provided in Section 10.3(b) shall be distributed to the Members in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 10.3(c)) for the taxable year of the Company during which the liquidation of the Company occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable year (or, if later, within 90 days after said date of such occurrence).

Section 10.4    Cancellation of Certificate of Formation.

Upon the completion of the distribution of Company cash and property as provided in Section 10.3 in connection with the liquidation of the Company, the Certificate of Formation and all qualifications of the Company as a foreign limited liability company in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Company shall be taken.

Section 10.5    Return of Contributions.

None of any member of the Board of Directors or any Officer will be personally liable for, or have any obligation to contribute or loan any monies or property to the Company to enable it to effectuate, the return of the Capital Contributions of the Members or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Company assets. A Member may not resign or withdraw from the Company prior to the dissolution and winding up of the Company, provided that the transfer of any Member Interest shall not constitute a breach or violation of this provision.

Section 10.6    Waiver of Partition.

To the maximum extent permitted by law, each Member hereby waives any right to partition of the Company property.

Section 10.7    Capital Account Restoration.

No Member shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Company.


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Article 11

AMENDMENT OF AGREEMENT; MEETINGS OF MEMBERS; RECORD DATE

Section 11.1    Amendment of Operating Agreement.

 

(a)   General Amendments.    Except as provided in Section 11.1(b) and Section 11.1(c), the Board of Directors may amend any of the terms of this Agreement but only in compliance with the terms, conditions and procedures set forth in this Section 11.1(a). If the Board of Directors desires to amend any provision of this Agreement other than pursuant to Section 11.1(c), then it shall first adopt a resolution setting forth the amendment proposed, declaring its advisability and either calling a special meeting of the Members entitled to vote in respect thereof for the consideration of such amendment or directing that the amendment proposed be considered at the next annual meeting of the Members. Amendments to this Agreement may be proposed only by or with the consent of the Board of Directors. Such special or annual meeting shall be called and held upon notice in accordance with Section 11.3 and Section 11.4 of this Agreement. The notice of such meeting shall set forth such amendment in full or a brief summary of the changes to be effected thereby, as the Board of Directors shall deem advisable. At the meeting, a vote of Members entitled to vote thereon shall be taken for and against the proposed amendment. Subject to Section 11.2(d), a proposed amendment shall be effective upon its approval by both a Unit Majority, unless a greater percentage is required by this Agreement.

 

(b)   Super-Majority Amendments.    Notwithstanding Section 11.1(a) but subject to Section 11.1(c), the affirmative vote of the holders of at least 75% of the Outstanding Common Units and 75% of the Outstanding Class A Units shall be required to alter, amend or adopt any provision inconsistent with or repeal this Section 11.1(b), Section 11.2, Section 11.3(d), Section 11.8(b), Section 11.8(c) or Section 11.12.

 

(c)   Amendments to be Adopted Solely by the Board of Directors.    Notwithstanding Section 11.1(a) and Section 11.1(b), the Board of Directors, without the approval of any Member or holder of any Company Securities, may amend any provision of this Agreement, and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

 

  (i)   a change in the name of the Company, the location of the principal place of business of the Company, the registered agent of the Company or the registered office of the Company;

 

  (ii)   admission, substitution, withdrawal or removal of Members in accordance with this Agreement;

 

  (iii)   a change that the Board of Directors determines to be necessary or appropriate to qualify or continue the qualification of the Company as a limited liability company under the laws of any state or to ensure that the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

 

  (iv)   a change that the Board of Directors determines (A) does not adversely affect the Members (including any particular class of Member Interests as compared to other classes of Member Interests) in any material respect, (B) to be necessary or appropriate to (1) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (2) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate

 

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uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which Units are or will be listed for trading, compliance with any of which the Board of Directors deems to be in the best interests of the Company and the Members, (C) to be necessary or appropriate in connection with action taken by the Board of Directors pursuant to Section 5.8 or (D) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

 

  (v)   a change in the fiscal year or taxable year of the Company and any other changes that the Board of Directors determines to be necessary or appropriate as a result of a change in the fiscal year or taxable year of the Company, including, if the Board of Directors shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Company;

 

  (vi)   an amendment that is necessary, in the Opinion of Counsel, to prevent the Company or its Directors, Officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

 

  (vii)   subject to Section 5.6, an amendment that the Board of Directors determines to be necessary or appropriate in connection with the authorization of issuance of any class or series of Company Securities pursuant to Section 5.5;

 

  (viii)   any amendment expressly permitted in this Agreement to be made by the Board of Directors acting alone;

 

  (ix)   an amendment effected, necessitated or contemplated by a Merger Agreement or Plan of Conversion approved in accordance with Section 12.3;

 

  (x)   an amendment that the Board of Directors determines to be necessary or appropriate to reflect and account for the formation by the Company of, or investment by the Company in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Company of activities permitted by the terms of Section 2.4;

 

  (xi)   a merger, consolidation, conversion or conveyance pursuant to Section 12.3(d);

 

  (xii)   an amendment that requires, in connection with a transfer of Member Interests, the Assignees of Member Interests to provide a statement, certification or other proof to the Company regarding such Assignee’s status as an Eligible Citizen; or

 

  (xiii)   any other amendments substantially similar to the foregoing.

Section 11.2    Amendment Requirements.

 

(a)   Notwithstanding the provisions of Section 11.1, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

 

(b)   Notwithstanding the provisions of Section 11.1, no amendment to this Agreement may (i) enlarge the obligations of any Member without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 11.2(c), (ii) change Section 10.1(a),

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(iii) change the term of the Company or (iv) except as set forth in Section 10.1(a), give any Person the right to dissolve the Company.

 

(c)   Except as provided in Section 12.3, and without limitation of the Board of Directors’ authority to adopt amendments to this Agreement without the approval of any Members as contemplated in Section 11.1 (including Section 11.1(c)(vii)), any amendment that would have a material adverse effect on the rights or preferences of any then Outstanding class of Member Interests in relation to other classes of Member Interests must be approved by the holders of not less than a majority of the Outstanding Member Interests of the class affected, provided that amending this Agreement to create a new class or series of Company Securities pursuant to Section 5.5 with relative rights, powers, preferences and duties that are senior or prior to, or pari passu with, the relative rights, powers, preferences or duties of any then Outstanding Member Interests shall not be deemed to cause such a material adverse effect.

 

(d)   Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 11.1(c) and except as otherwise provided by Section 12.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Common Units and Class A Units, voting as a single class, unless the Company obtains an Opinion of Counsel to the effect that such amendment will not adversely affect the limited liability of any Member under applicable law.

Section 11.3    Unitholder Meetings.

 

(a)   All acts of Members to be taken hereunder shall be taken in the manner provided in this Article 11. An annual meeting of the Members for the election of Directors and for the transaction of such other business as may properly come before the meeting shall be held at such time and place as the Board of Directors shall specify, which date shall be within 13 months of the last annual meeting of Members. If authorized by the Board of Directors, and subject to such guidelines and procedures as the Board of Directors may adopt, Members and proxyholders not physically present at a meeting of Members, may by means of remote communication participate in such meeting, and be deemed present in person and vote at such meeting provided that the Company shall implement reasonable measures to verify that each Person deemed present and permitted to vote at the meeting by means of remote communication is a Member or proxyholder, to provide such Members or proxyholders a reasonable opportunity to participate in the meeting and to record the votes or other action made by such Members or proxyholders.

 

(b)   A failure to hold the annual meeting of the Members at the designated time or to elect a sufficient number of Directors to conduct the business of the Company shall not affect otherwise valid acts of the Company or work a forfeiture or dissolution of the Company. If the annual meeting for election of Directors is not held on the date designated therefor, the Directors shall cause the meeting to be held as soon as is convenient. If there is a failure to hold the annual meeting for a period of 30 days after the date designated for the annual meeting, or if no date has been designated, for a period of 13 months after the latest to occur of the date of this Agreement or its last annual meeting, it is the intent of the parties that the Delaware Court of Chancery may summarily order a meeting to be held upon the application of any Member or Director. The Outstanding Units present at such meeting, either in person or by proxy, and entitled to vote thereat, shall constitute a quorum for the purpose of such meeting, notwithstanding any provision of this Agreement to the contrary. The Delaware Court of Chancery may issue such orders as may be appropriate, including orders designating the time and place of such meeting, the record date for determination of Unitholders entitled to vote, and the form of notice of such meeting.

 

(c)   All elections of Directors will be by written ballots; if authorized by the Board of Directors, such requirement of a written ballot shall be satisfied by a ballot submitted by electronic transmission,

 

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provided that any such electronic transmission must either set forth or be submitted with information from which it can be reasonably determined that the electronic transmission was authorized by the Member or proxyholder.

 

(d)   Special meetings of the Members, for any purpose or purposes, may be called by (i) the Chairman of the Board or the Vice Chairman of the Board, if there be either, (ii) the Chief Executive Officer, (iii) the President (iv) a majority of the entire Board of Directors. No Members or group of Members, acting in its or their capacity as Members, shall have the right to call a special meeting of the Members.

 

(e)   Any action required to be taken at any annual or special meeting of the Unitholders or any action that may be taken at any annual or special meeting of the Unitholders may be taken without a meeting, without prior notice and without a vote if a consent in writing, setting forth the action so
  taken, shall be signed by the holders of outstanding Units having not less than the minimum number of votes that would be necessary to authorize to take such action at a meeting at which all Units entitled to vote thereon were present and voted and shall be delivered to the Company.

Section 11.4    Notice of Meetings of Members.

 

(a)   Notice, stating the place, day and hour of any annual or special meeting of the Members, as determined by the Board of Directors, and (i) in the case of a special meeting of the Members, the purpose or purposes for which the meeting is called, as determined by the Board of Directors or (ii) in the case of an annual meeting, those matters that the Board of Directors, at the time of giving the notice, intends to present for action by the Members, shall be delivered by the Company 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 Section 14.1 to each Record Holder who is entitled to vote at such meeting. Such further notice shall be given as may be required by applicable law. The notice of any meeting of the Members at which Directors are to be elected shall include the name of any nominee or nominees who, at the time of the notice, the Board of Directors intends to present for election. Only such business shall be conducted at a special meeting of Members as shall have been brought before the meeting pursuant to the Company’s notice of meeting. Any previously scheduled meeting of the Members may be postponed, and any special meeting of the Members may be canceled, by resolution of the Board of Directors upon public notice given prior to the date previously scheduled for such meeting of the Members.

 

(b)   The Board of Directors shall designate the place of meeting for any annual meeting or for any special meeting of the Members. If no designation is made, the place of meeting shall be the principal office of the Company.

Section 11.5    Record Date.

For purposes of determining the Members entitled to notice of or to vote at a meeting of the Members or to give approvals without a meeting as provided in Section 11.3(e), the Board of Directors may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Common Units are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Members are requested by the Board of Directors to give such approvals. If no Record Date is fixed by the Board of Directors, then (a) the Record Date for determining Members entitled to notice of or to vote at a meeting of Members shall be at the close of business on the day next preceding the day on which notice is given and (b) the Record Date for determining the Members entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Company in care of the Board of Directors. A determination of Members of record


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entitled to notice of or to vote at a meeting of Members shall apply to any adjournment or postponement of the meeting; provided, however, that the Board of Directors may fix a new Record Date for the adjourned or postponed meeting.

Section 11.6    Adjournment.

The Chairman of the Board, or other chairman of such meeting, may adjourn any meeting of the Members, whether for lack of a quorum or any other reason. When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 30 days. At the adjourned meeting, the Company may transact any business that might have been transacted at the original meeting. If the adjournment is for more than 30 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article 11.

Section 11.7    Waiver of Notice; Approval of Meeting.

Whenever notice to the Members is required to be given under this Agreement, a written waiver, signed by the Person entitled to notice, whether before or after the time stated therein, shall be deemed equivalent to notice. Attendance of a Person at any such meeting of the Members shall constitute a waiver of notice of such meeting, except when the Person attends a meeting for the express purpose of objecting at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the Members need be specified in any written waiver of notice unless so required by resolution of the Board of Directors. All waivers and approvals shall be filed with the Company records or made part of the minutes of the meeting.

Section 11.8    Quorum; Required Vote for Member Action; Voting for Directors.

 

(a)   At any meeting of the Members, the holders of a majority of the Outstanding Units or Member Interests of each class then outstanding and entitled to vote, represented in person or by proxy, shall constitute a quorum of such class or classes unless any such action by the Members requires approval by holders of a greater percentage of Outstanding Units or Member Interests, in which case the quorum shall be such greater percentage. The submission of matters to Members for approval and the election of Directors shall occur only at a meeting of the Members duly called and held in accordance with this Agreement at which a quorum is present; provided, however, that the Members present at a duly called and held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Members to leave less than a quorum, if any action taken (other than adjournment) is approved by the required percentage of Member Interests specified in this Agreement. In the absence of a quorum any meeting of Members may be adjourned from time to time by the chairman of the meeting to another place or time.

 

(b)   The Members holding Outstanding Common Units and Class A Units shall be entitled to one vote per Unit on all matters submitted to Members for approval and in the election of Directors.

 

(c)   Except as otherwise provided in this Agreement, all matters submitted to Members for approval shall be determined by a majority of the votes cast affirmatively or negatively by Members holding Outstanding Units unless a greater percentage is required with respect to such matter under the Delaware Act, under the rules of any National Securities Exchange on which the Common Units are listed for trading, or under the provisions of this Agreement, in which case the approval of Members holding Units that in the aggregate represent at least such greater percentage shall be required. Directors will be elected by a plurality of the votes cast for a particular position.

 

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(d)   The right of the holders of the Class A Units to vote as a class pursuant to Section 10.1(a) and Section 12.3(b) may be terminated at any duly called meeting of the Members upon the affirmative vote of holders of not less than 66 2/3% of Outstanding Common Units.

Section 11.9    Conduct of a Meeting; Member Lists.

 

(a)   The Board of Directors shall have full power and authority concerning the manner of conducting any meeting of the Members, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of this Article 11, the conduct of voting, the validity and effect of any proxies and (subject to Section 11.11(d)) the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The Board of Directors shall have the power to designate a Person to serve as chairman of any meeting
  and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Company maintained by the Board of Directors. The Board of Directors may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Members, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes, the submission and examination of proxies and other evidence of the right to vote.

 

(b)   A complete list of Members entitled to vote at any meeting of Members, arranged in alphabetical order for each class of Member Interests and showing the address of each such Member and the number of Outstanding Units or Member Interests registered in the name of such Member, shall be open to the examination of any Member, for any purpose germane to the meeting, during ordinary business hours, for a period of at least 10 days before the meeting, at the principal place of business of the Company. The Member list shall also be produced and kept at the time and place of the meeting during the whole time thereof, and may be inspected by any Member who is present.

Section 11.10    Voting and Other Rights.

 

(a)   Only those Record Holders of Outstanding Units and Member Interests on the Record Date established pursuant to Section 11.5 shall be entitled to notice of, and to vote at, a meeting of Members or to act with respect to matters as to which the holders of the Outstanding Units and Member Interests have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units and Member Interests shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units and Member Interests.

 

(b)   With respect to Outstanding Units or Member Interests that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Outstanding Units or Member Interests are registered, such other Person shall, in exercising the voting rights in respect of such Outstanding Units or Member Interests on any matter, and unless the arrangement between such Persons provides otherwise, vote such Outstanding Units or Member Interests in favor of, and at the direction of, the Person who is the beneficial owner, and the Company shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 11.10(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

Section 11.11    Proxies and Voting.

 

(a)   At any meeting of the Members, every holder of an Outstanding Unit or Member Interests entitled to vote may vote in person or by proxy authorized by an instrument in writing or by a transmission permitted by law filed in accordance with the procedure established for the meeting. Any copy, facsimile telecommunication or other reliable reproduction of the writing or transmission created

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pursuant to this paragraph may be substituted or used in lieu of the original writing or transmission for any and all purposes for which the original writing or transmission could be used, provided that such copy, facsimile telecommunication or other reproduction shall be a complete reproduction of the entire original writing or transmission.

 

(b)   The Company may, and to the extent required by law, shall, in advance of any meeting of Members, appoint one or more inspectors to act at the meeting and make a written report thereof. The Company may designate one or more alternate inspectors to replace any inspector who fails to act. If no inspector or alternate is able to act at a meeting of Members, the Person presiding at the meeting may, and to the extent required by law, shall, appoint one or more inspectors to act at the meeting. Each inspector, before entering upon the discharge of his or her duties, shall take and sign an oath faithfully to execute the duties of inspector with strict impartiality and according to the best of his or her ability. Every vote taken by ballots shall be counted by a duly appointed inspector or inspectors.

 

(c)   With respect to the use of proxies at any meeting of Members, the Company shall be governed by paragraphs (b), (c), (d) and (e) of Section 212 of the DGCL and other applicable provisions of the DGCL, as though the Company were a Delaware corporation and as though the Members were stockholders of a Delaware corporation.

 

(d)   With respect to any contested matter relating to any election, appointment, removal or resignation of any Director, to the fullest extent permitted by law, the Company shall be governed by Section 225 of the DGCL and any other applicable provision of the DGCL, as though the Company were a Delaware corporation.

Section 11.12    Notice of Member Business and Nominations.

 

(a)   A Unitholder may bring a matter of business or nominations for the election of Directors before a meeting of Members only if: (a) such business may otherwise be properly be brought before the meeting, (b) such Unitholder shall have given, and the Company shall have received at its principal executive offices addressed to the Secretary, written notice in proper form of such matter not less than 90 days prior to the first anniversary date of the mailing date of the Company’s proxy solicitation materials for the previous year’s annual meeting of Members, and (c) in the case of a special meeting of Members, such business is within the purpose or purposes specified in the notice of the meeting and such Unitholder shall have given, and the Company shall have received its principal executive offices addressed to the Secretary, written notice in proper form of such matter not less than 90 days prior to the date of the special meeting. To be in proper form, a Unitholder’s notice to the Secretary shall set forth:

 

  (i)   the name and address of the Unitholder who intends to make the nominations, propose the business, and, as the case may be, the name and address of the Person or Persons to be nominated or the nature of the business to be proposed;

 

  (ii)   a representation that the Unitholder is a Record Holder of Outstanding Units entitled to vote at such meeting and, if applicable, intends to appear in person or by proxy at the meeting to nominate the Person or Persons specified in the notice or introduce the business specified in the notice;

 

  (iii)   if applicable, a description of all arrangements or understandings between the Unitholder and each nominee and any other Person (naming such Person) pursuant to which the nomination or nominations are to be made by the Unitholder;

 

  (iv)   such other information regarding each nominee or each matter of business to be proposed by such Unitholder as would be required to be included in a proxy statement filed pursuant to the

 


 

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proxy rules of the Commission had the nominee been nominated, or intended to be nominated, or the matter been proposed, or intended to be proposed, by the Board of Directors; and

 

  (v)   if applicable, the consent of each nominee to serve as Director if so elected.

The chairman of the meeting may refuse to acknowledge the nomination of any Person or the proposal of any business not made in compliance with the foregoing procedure.

 

(b)   Notwithstanding the foregoing provisions of this Section 11.12, a Member shall also comply with all applicable requirements of the Exchange Act and the rules and regulations thereunder with respect to the matters set forth in this Section 11.12. Nothing in this Section 11.12 shall be deemed to affect any rights of Members to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.

Article 12

MERGER, CONSOLIDATION OR CONVERSION

Section 12.1    Authority.

The Company may merge or consolidate with one or more limited liability companies or “other business entity” as defined in Section 18-209 of the Delaware Act, or convert into any “other entity” as defined in Section 18-214 of the Delaware Act, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article 12.

Section 12.2    Procedure for Merger, Consolidation or Conversion.

 

(a)   Merger, consolidation or conversion of the Company pursuant to this Article 12 requires the prior approval of the Board of Directors, provided, however, that, to the fullest extent permitted by law, the Board of Directors shall have no duty or obligation to consent to any merger, consolidation or conversion of the Company and may decline to do so free of any fiduciary duty or obligation whatsoever to the Company or any Member and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

 

(b)   If the Board of Directors shall determine to consent to a merger or consolidation, the Board of Directors shall approve the Merger Agreement, which shall set forth:

 

  (i)   the names and jurisdiction of domicile of each of the business entities proposing to merge or consolidate;

 

  (ii)   the name and jurisdiction of domicile of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

 

  (iii)   the terms and conditions of the proposed merger or consolidation;

 

  (iv)   the manner and basis of exchanging or converting the rights or securities of, or interests in, each constituent business entity for, or into, cash, property, rights, or obligations of, securities of or interests in, the Surviving Business Entity; and (A) if any rights or securities of, or interests in, any constituent business entity are not to be exchanged or converted solely for, or into, cash, property, rights, or obligations of, securities of or interests in, the Surviving Business Entity, the

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cash, property, rights, or obligations of, securities of or interests in, any limited liability company or other business entity which the holders of such rights, securities or interests are to receive in exchange for, or upon conversion of their interests, securities or rights, and (B) in the case of securities represented by certificates, upon the surrender of such certificates, which cash, property, rights, or obligations, of securities of or interests in, the Surviving Business Entity or any other business entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

 

  (v)   a statement of any changes in the constituent documents or the adoption of new constituent documents (the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

 

  (vi)   the effective time of the merger or consolidation, which may be the date of the filing of the certificate of merger pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger or consolidation is to be later than the date of the filing of the certificate of merger, the effective time shall be fixed at a date no later than the time of the filing of the certificate of merger and stated therein); and

 

  (vii)   such other provisions with respect to the proposed merger or consolidation that the Board of Directors determines to be necessary or appropriate.

 

(c)   If the Board of Directors shall determine to consent to a conversion, the Board of Directors shall approve the Plan of Conversion, which shall set forth:

 

  (i)   the name of the converting entity and the converted entity;

 

  (ii)   a statement that the Company is continuing its existence in the organizational form of the converted entity;

 

  (iii)   a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

 

  (iv)   the manner and basis of exchanging or converting the equity securities of the converting entity for, into securities of or interests in the converted entity or other property;

 

  (v)   in an attachment or exhibit, the certificate of formation of the Company; and

 

  (vi)   in an attachment or exhibit, the certificate of formation or limited liability company agreement, articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership or other similar charter or governing document of the converted entity;

 

  (vii)   the effective time of the conversion, which may be the date of the filing of the certificate of conversion pursuant to Section 12.4 or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such certificate of conversion, the effective time shall be fixed at a date or time certain at or prior to the time of the filing of such certificate of conversion and stated therein); and

 

  (viii)   such other provisions with respect to the proposed conversion that the Board of Directors determines to be necessary or appropriate.

 


 

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Section 12.3    Approval by Members of Merger, Consolidation or Conversion.

 

(a)   Except as provided in Section 12.3(d), the Board of Directors, upon its approval of the Merger Agreement or Plan of Conversion, as the case may be, shall direct that the Merger Agreement or Plan of Conversion, as applicable, be submitted to a vote of Members, whether at an annual meeting or a special meeting, in either case in accordance with the requirements of Article 11. A copy or a summary of the Merger Agreement or Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of meeting or the written consent.

 

(b)   Except as provided in Section 12.3(d), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Class A Unit Majority and a Common Unit Majority unless the Merger Agreement or Plan of Conversion, as applicable, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Members, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or Plan of Conversion, as applicable.

 

(c)   Except as provided in Section 12.3(d), after such approval by vote or consent of the Members, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 12.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as applicable.

 

(d)   Notwithstanding anything else contained in this Article 12 or in this Agreement, the Board of Directors is permitted without Member approval, to convert the Company or any Group Member into a new limited liability entity, to merge the Company or any Group Member into, or convey all of the Company’s assets to, another limited liability entity which shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Company or other Group Member if (i) the Board of Directors has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability of any Member or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such conversion, merger or conveyance is to effect a mere change in the legal form of the Company into another limited liability entity and (iii) the governing instruments of the new entity provide the Members and the Board of Directors with the same rights and obligations as are herein contained.

 

(e)   Additionally, notwithstanding anything else contained in this Article 12 or in this Agreement, the Board of Directors is permitted without Member approval to merge or consolidate the Company with or into another entity if (A) the Board of Directors has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability of any Member under Delaware law or cause the Company to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement other than any amendments that could be adopted pursuant to Section 11.1(c), (C) the Company is the Surviving Business Entity in such merger or consolidation, (D) each Member Interest outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Member Interest of the Company after the effective date of the merger or consolidation, and (E) the number of Company Securities to be issued by the Company in such merger or consolidation do not exceed 20% of the Company Securities Outstanding immediately prior to the effective date of such merger or consolidation.

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(f)   Pursuant to Section 18-209(f) of the Delaware Act, a Merger Agreement approved in accordance with this Article 12 may (i) effect any amendment to this Agreement or (ii) effect the adoption of a new limited liability company agreement for the Company if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 12.3 shall be effective at the effective time or date of the merger or consolidation.

 

(g)   Members are not entitled to dissenters’ rights of appraisal in the event of a merger, consolidation or conversion pursuant to Section 12.1, a sale of all or substantially all of the assets of the Company or the Company’s Subsidiaries, or any other transaction or event.

Section 12.4    Certificate of Merger; Certificate of Conversion.

Upon the required approval by the Board of Directors and the Unitholders of a Merger Agreement, a certificate of merger, or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 12.5    Effect of Merger or Conversion.

 

(a)   At the effective time of the certificate of merger:

 

  (i)   all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

 

  (ii)   the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

 

  (iii)    all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

 

  (iv)   all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

 

(b)   At the effective time of the certificate of conversion:

 

  (i)   the other entity or business form shall be deemed to be the same entity as the Company and the conversion shall constitute a continuation of the existence of the Company in the form of such other entity or business form;

 

  (ii)   such conversion shall not be deemed to affect any obligations or liabilities of the Company incurred prior to such conversion or the personal liability of any person incurred prior to such conversion, nor shall it be deemed to affect the choice of law applicable to the Company with respect to matters arising prior to such conversion;

 

  (iii)    the other entity or business form shall, for all purposes of the laws of the State of Delaware, be deemed to be the same entity as the Company;

 

  (iv)   all of the rights, privileges and powers of the Company that has converted, and all property, real, personal and mixed, and all debts due to the Company, as well as all other things and causes of action belonging to the Company, shall remain vested in the other entity or business form to which the Company has converted and shall be the property of such other entity or business form, and the title to any real property vested by deed or otherwise in the Company shall not revert or be in any way impaired;

 


 

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  (v)   all rights of creditors and all liens upon any property of the Company shall be preserved unimpaired, and all debts, liabilities and duties of the Company shall remain attached to the other entity or business form to which the Company has converted, and may be enforced against it to the same extent as if said debts, liabilities and duties had originally been incurred or contracted by it in its capacity as such other entity or business form;

 

  (vi)   the rights, privileges, powers and interests in property of the Company, as well as the debts, liabilities and duties of the Company, shall not be deemed, as a consequence of the conversion, to have been transferred to the other entity or business form to the Company has converted for any purpose of the laws of the State of Delaware; and

 

  (vii)   the Company Securities that are to be exchanged for or converted into cash, property, rights or securities of or interests in the entity or business form into which the Company is being converted shall be so exchanged or converted in accordance with the Plan of Conversion, or, in
  addition to or in lieu thereof, if the Plan of Conversion so provides, the Company Securities may be exchanged for or converted into cash, property, rights or securities of or interests in another entity or business form or may be cancelled.

 

(c)   It is the intent of the parties hereto that a merger, consolidation or conversion effected pursuant to this Article 12 shall not be deemed to result in a transfer or assignment of assets, liabilities, debts or duties from one entity to another.

Section 12.6    Business Combination Limitations.

Notwithstanding any other provision of this Agreement, with respect to any “Business Combination” (as such term is defined in Section 203 of the DGCL), the provisions of Section 203 of the DGCL shall be applied with respect to the Company as though the Company were a Delaware corporation.

Article 13

RIGHT TO ACQUIRE MEMBER INTERESTS

Section 13.1    Right to Acquire Member Interests.

 

(a)   Notwithstanding any other provision of this Agreement, if at any time any Person holds more than 87.5% of the total Member Interests of any class then Outstanding, such Person shall then have the right, which right it may assign and transfer in whole or in part to the Company or any of its Affiliates, exercisable at its option, to purchase all, but not less than all, of such Member Interests of such class then Outstanding held by other holders, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 13.1(b) is mailed and (y) the highest price paid by such Person or any of its Affiliates for any such Member Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 13.1(b) is mailed.

 

(b)   If any Person elects to exercise the right to purchase Member Interests granted pursuant to Section 13.1(a), the Board of Directors shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Member Interests of such class (as of a Record Date selected by the Board of Directors) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to

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Purchase shall specify the Purchase Date and the price (determined in accordance with Section 13.1(a)) at which Member Interests will be purchased and state that such Person elects to purchase such Member Interests, upon surrender of Certificates representing such Member Interests in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Member Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Member Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the Person exercising the right to purchase hereunder shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Member Interests to be purchased in accordance with this Section 13.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Member Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Member Interests (including any rights pursuant to Article 4, Article 5, Article 6, and Article 10) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 13.1(a)) for Member Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Member Interests, and such Member Interests shall thereupon be deemed to be transferred to the Person exercising the right to purchase hereunder on the record books of the Transfer Agent and the Company, and such Person shall be deemed to be the owner of all such Member Interests from and after the Purchase Date and shall have all rights as the owner of such Member Interests (including all rights as owner of such Member Interests pursuant to Article 4, Article 5, Article 6, and Article 10).

 

(c)   At any time from and after the Purchase Date, a holder of an Outstanding Member Interest subject to purchase as provided in this Section 13.1 may surrender his Certificate evidencing such Member Interest to the Transfer Agent in exchange for payment of the amount described in Section 13.1(a), therefor, without interest thereon.

 

(d)   Upon the exercise by any Person of the right to purchase Member Interests granted pursuant to Section 13.1(a), no Member shall be entitled to dissenters’ rights of appraisal.

Article 14

GENERAL PROVISIONS

Section 14.1    Addresses and Notices.

Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Member under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Member at the address described below. Any notice, payment or report to be given or made to a Member hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Company Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Company, regardless of any claim of any Person who may have an interest in such Company Securities by reason of any assignment or otherwise. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 14.1 executed by the Company, the Transfer

 


 

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Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report addressed to a Record Holder at the address of such Record Holder appearing on the books and records of the Transfer Agent or the Company is returned by the United States Postal Service marked to indicate that the United States Postal Service is unable to deliver it, such notice, payment or report and any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Company of a change in his address) if they are available for the Member at the principal office of the Company for a period of one year from the date of the giving or making of such notice, payment or report to the other Members. Any notice to the Company shall be deemed given if received by the Secretary at the principal office of the Company designated pursuant to Section 2.3. The Board of Directors and the Officers may rely and shall be protected in relying on any notice or other document from a Member or other Person if believed by it to be genuine.

Section 14.2    Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 14.3    Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

Section 14.4    Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 14.5    Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Company.

Section 14.6    Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 14.7    Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Common Unit, upon accepting the Certificate evidencing such Common Unit.

Section 14.8    Applicable Law.

This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware without regard to principles of conflicts of laws.


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Section 14.9    Invalidity of Provisions.

If any provision of this Agreement is or becomes invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions contained herein shall not be affected thereby.

Section 14.10    Consent of Members.

Each Member hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Members, such action may be so taken upon the concurrence of less than all of the Members and each Member shall be bound by the results of such action.

[Remainder of page intentionally left blank.]

 


 

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

ATLAS AMERICA, INC.
By:     
  Name:
 

Its:   


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EXHIBIT A

to the Amended and

Restated Operating Agreement of

Atlas Energy Resources, LLC

 

NUMBER                                   COMMON UNITS

CERTIFICATE EVIDENCING COMMON UNITS

REPRESENTING LIMITED LIABILITY COMPANY INTERESTS IN

ATLAS ENERGY RESOURCES, LLC

A LIMITED LIABILITY COMPANY FORMED UNDER THE LAWS OF

DELAWARE

CUSIP [            ]

SEE REVERSE FOR

CERTAIN DEFINITIONS

In accordance with Section 4.1 of the Amended and Restated Operating Agreement of Atlas Energy Resources, LLC, as amended, supplemented or restated from time to time (the “Company Agreement”), Atlas Energy Resources, LLC, a Delaware limited liability company (the “Company”), hereby certifies that [            ] (the “Holder”) is the registered owner of [            ] Common Units representing Interests in the Company (the “Units”) transferable on the books of the Company, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Units are set forth in, and this Certificate and the Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Company Agreement. Copies of the Company Agreement are on file at, and will be furnished without charge on delivery of written request to the Company at, the principal office of the Company located at 311 Rouser Road, Moon Township, PA 15108 or such other address as may be specified by notice under the Company Agreement. Capitalized terms used herein but not defined shall have the meanings given them in the Company Agreement.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Member and to have agreed to comply with and be bound by and to have executed the Company Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Company Agreement, (iii) granted the powers of attorney provided for in the Company Agreement, and (iv) made the waivers and given the consents and approvals contained in the Company Agreement.

This Certificate shall be governed by, and construed in accordance with, the laws of the State of Delaware, without regard to principles of conflict of laws thereof.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF THE COMPANY THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER. THE COMPANY MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF THE COMPANY BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL

 



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INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar.

 

Dated:     Atlas Energy Resources, LLC
      By:     
      By:     
       

Countersigned and Registered by:

 

American Stock Transfer & Trust Company,

as Transfer Agent and Registrar

By:     
  Authorized Signature

 



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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM    as tenants in common    UNIF GIFT/TRANSFERS MIN ACT             Custodian         
TEN ENT    as tenants by the entireties       (Cust)             (Minor)
JT TEN    as joint tenants with right of survivorship and not as tenants in common      

under Uniform Gifts/Transfers to Minors Act

_______________

        (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF UNITS

in

ATLAS ENERGY RESOURCES, LLC

FOR VALUE RECEIVED,                                                   hereby assigns, conveys, sells and transfers unto

            (Please insert Social Security or other identifying number of Assignee)             

            (Please print or typewrite name and address of Assignee)

             Common Units representing limited liability company interests evidenced by this Certificate, subject to the Company Agreement, and does hereby irrevocably constitute and appoint                  as its attorney-in-fact with full power of substitution to transfer the same on the books of Atlas Energy Resources, LLC.

 

Date:                          NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular, without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15        
    (Signature)
      
    (Signature)
      
SIGNATURE(S) GUARANTEED    

 



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Appendix B

Glossary of Terms

The terms defined in this glossary are used throughout this prospectus.

BBL—One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

BCF—One billion cubic feet of natural gas.

BCFE—One billion cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

BTU—British thermal unit.

COMPLETION—The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting of abandonment to the appropriate production.

DEVELOPMENT WELL—A well drilled within the proved boundaries of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

DRY WELL—A development or exploratory well found to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as an oil or natural gas well.

EXPLORATORY WELL—A well drilled to find natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir, or to extend a known reservoir.

FERC—Federal Energy Regulatory Commission.

FINDING AND DEVEOPMENT COSTS—Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

GROSS ACRES or GROSS WELLS—The total number of acres or wells, as the case may be, in which a working interest is owned.

IDENTIFIED DRILLING LOCATIONS—Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBBL—One thousand barrels of crude oil or other liquid hydrocarbons.

MCF—One thousand cubic feet of natural gas.

MCFE—One thousand cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

 


 

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MMCFE—One million cubic feet of natural gas equivalents, converting one Bbl of oil to six Mcf of natural gas.

MMCF—One million cubic feet of natural gas.

MMBTU—One million British thermal units.

MMCFE/D—One Mmcfe per day.

NET ACRES or NET WELLS—The sum of the fractional working interests owned in gross acres or gross wells. For example, a 50% working interest in a well is one gross well, but is a 0.50 net well.

NYMEX—New York Mercantile Exchange.

PRESENT VALUE OF FUTURE NET REVENUES (PV-10)—The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities (but including our forward sales), non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%.

PRODUCING WELL, PRODUCTION WELL or PRODUCTIVE WELL—A well that is producing natural gas or oil or that is capable of production.

PROVED DEVELOPED RESERVES—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

PROVED RESERVES—The estimated quantities of natural gas, crude oil 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.

PROVED UNDEVELOPED RESERVES—Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

RECOMPLETION—The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

ROYALTY INTEREST—An interest in a natural gas and oil property entitling the owner to a share of natural gas and oil production free of costs of production.

STANDARIZED MEASURE—The present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes. Upon completion of this offering, our PV-10 and standardized measure values will be the same because we are not subject to income taxes.

 


 

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TCF—One trillion cubic feet of natural gas.

UNDEVELOPED ACREAGE—Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

WORKING INTEREST—The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

 


 

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Appendix C

July 12, 2006

Atlas America, Inc.

311 Rouser Road

Moon Township, PA 15108-2719

ATTENTION: Mr. Jeffrey C. Simmons

Gentlemen:

 

SUBJECT:    EXECUTIVE SUMMARY REPORT
   Evaluation of Oil and Gas Reserves
   To the Interests of
   Atlas America, Inc.
   In Certain Properties Located in Various States
   Pursuant to the Requirements of the
   Securities and Exchange Commission
   Effective March 31, 2006
   Job 06.894

Wright & Company, Inc. (Wright) has performed an evaluation to estimate proved reserves and cash flow from certain oil and gas properties owned by Atlas America, Inc. (AAI). This evaluation was authorized by Mr. Jeffrey C. Simmons of AAI. AAI intends to contribute all the properties included in the evaluation to a new company, Atlas Energy Resources, LLC (AER), being formed as a Delaware limited liability company. AER will own and operate all of the natural gas and oil exploration and production assets which will be transferred. It is Wright’s understanding that the AAI assets will be contributed to AER within 180 days following the effective date of this report.

Projections of the reserves and cash flow to the evaluated interests were based on economic parameters and operating conditions considered to be applicable as of March 31, 2006, and are pursuant to the financial reporting requirements of the Securities and Exchange Commission (SEC).

 


 

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Table of Contents

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 2


 

Some of the information contained in this report is based on the report prepared by Wright entitled “EXECUTIVE SUMMARY REPORT, Evaluation of Oil and Gas Reserves to the Interests of Atlas America, Inc. In Certain Properties Located in Various States, Pursuant to the Requirements of the Securities and Exchange Commission, Effective September 30, 2005, Job 05.836,” dated October 28, 2005, hereinafter referred to as the Prior Report. The purpose of this report is to update the Prior Report with new information including, but not limited to, new production on certain wells, product prices as of March 31, 2006, and new wells drilled subsequent to September 30, 2005, which were completed on or before March 31, 2006; however, this report does not include the addition of any new proved undeveloped (PUD) reserves as Wright was not requested to evaluate any new well locations for categorization as PUD locations.

The following is a summary of the results of the evaluation, effective March 31, 2006:

 

     

Proved

Developed

Producing

(PDP)

  

Proved

Developed

Nonproducing

(PDNP)

   Proved
Developed
Nonproducing
Behind Pipe
(PDBP)
  

Proved

Undeveloped

(PUD)

  

Total

Proved

Net Reserves to the Evaluated Interests

              

Oil, Mbbl:

   1,991.897    25.760    0.000    120.318    2,137.975

Gas, Mmcf:

   99,588.437    8,270.131    30.009    50,221.487    158,110.064

Cash Flow (BTAX), M$

              

Undiscounted:

   709,084.396    54,221.334    160.559    230,520.954    993,987.243

Discounted at 10%

              

Per Annum:

   321,396.204    28,271.647    73.110    62,631.792    412,372.753

For purposes of this report, unless otherwise noted, AAI and AER will hereinafter be collectively referred to as Atlas.

The individual projections of lease reserves and economics were generated using certain data that describe the production forecasts and all associated evaluation parameters such as interests, severance and ad valorem taxes, product prices, operating expenses, investments, salvage values, and abandonment costs, as applicable. The data reports are not presented in this report individually, but are a part of Wright’s work product and are retained in our files. This report is an EXECUTIVE SUMMARY REPORT as requested by Atlas, and does not include one-line tabulations by well in accordance with their instructions.

The properties evaluated in this report are located in the states of Arkansas, Kansas, Kentucky, Louisiana, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, West Virginia, and Wyoming. It is the understanding of Wright that the interests evaluated on behalf of Atlas are (i) those interests that may be owned by Atlas through various entities that are direct or indirect wholly owned subsidiaries of Atlas (Atlas Subsidiaries) as well as (ii) interests owned by investment partnerships in which the Atlas Subsidiaries own a minority equity interest (in which case the interests evaluated include the proportionate interest of the Atlas Subsidiaries in the property interests in those other entities).


 

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Table of Contents

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 3


 

Net income to the evaluated interests is the cash flow after consideration of royalty revenue payable to others, standard state severance and ad valorem taxes, operating expenses, investments, salvage values, and abandonment costs, as applicable. The cash flow is before federal income tax (BTAX) and excludes consideration of any encumbrances against the properties if such exist.

The Cash Flow (BTAX) values presented in this report were based on projections of annual oil and gas sales. It was assumed there would be no significant delay between the date of oil and gas production and the receipt of the associated revenue for this production.

Unless specifically identified and documented by Atlas as having curtailment problems, gas production forecasts have been assumed to be a function of well productivity and not of market conditions. The effect of “take or pay” clauses in gas contracts, if there were such clauses, was not considered for this evaluation.

Oil and gas reserves were evaluated for the proved developed producing (PDP), proved developed nonproducing (PDNP), proved developed nonproducing behind pipe (PDBP), and proved undeveloped (PUD) categories. The summary classification of proved developed reserves combines the PDP, PDNP, and PDBP categories. For the PDP category, reserves were based primarily on decline curve analysis projections where sufficient production history was available. For reserves assigned to the PDNP category, the production start dates for wells drilled during fiscal 2006 that were not producing at the effective date were estimated by Atlas. Atlas requested that Wright include summaries of shut-in (PDNP-SI) and temporarily abandoned (PDNP-TA) properties for well count purposes only. There is no value associated with the properties in these categories in this report. According to Atlas, there are 552 PDNP-SI and PDNP-TA wells, of which 491 are operated by Atlas, and these properties will also be transferred to AER. For the PUD category, reserves were based on a mathematical average of the estimated ultimate recovery (EUR) of PDP direct offset wells, or a larger number of wells producing from the same formation in the same township or area.

In preparing this evaluation, no attempt has been made to quantify the element of uncertainty associated with any category. Reserves were assigned to each category as warranted. The attached Definitions of Oil and Gas Reserves describe all categories of proved reserves.

Oil reserves are expressed in thousands of United States (U.S.) barrels (Mbbl), one barrel equaling 42 U.S. gallons. Gas volumes are expressed in millions of standard cubic feet (Mmcf) at 60 degrees Fahrenheit and at the legal pressure base that prevails in the state in which the reserves are located. No adjustment of the individual gas volumes to a common pressure base has been made.

The Cash Flow (BTAX) was discounted at an annual rate of 10.00 percent (10.00 PCT) as requested by Atlas, and in accordance with the reporting requirements of the SEC. Future cash flow was also discounted at several secondary rates as indicated on each reserves and economics page. These additional discounted amounts are displayed as totals only. The cash flow was discounted at the midpoint of the period, compounded annually.

This report includes only those costs and revenues which were provided by Atlas that are directly attributable to the individual leases and areas. There could exist other revenues, overhead costs, or other costs associated with Atlas which are not included in this report. Such additional costs and revenues are


 

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Table of Contents

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 4


 

outside the scope of this report. It should be noted that no opinion is expressed by Wright as to the fair market value of the evaluated properties. This report is not a financial statement for Atlas and should not be used as the sole basis for any transaction concerning Atlas or the evaluated properties.

All data utilized in the preparation of this report with respect to interests, oil and gas prices, gas contract terms, operating expenses, investments, salvage values, abandonment costs, well information, and current operating conditions, as applicable, were provided by Atlas. Data obtained after the effective date of the report, but prior to the completion of the report, were used only if such data were applied consistently. If such data were used, the reserves category assignments reflect the status of the wells as of the effective date. All production data were provided by Atlas. According to Atlas, some of the historical production provided may be incomplete. Wright has reviewed all data for reasonableness and, unless obvious errors were detected, has accepted the data as correct. It should be emphasized that revisions to the projections of reserves and economics included in this report may be required if the provided data are revised for any reason. No inspection of the properties was made as this was not considered to be within the scope of this evaluation.

The estimates of reserves contained in this report were determined by accepted industry methods and in accordance with the attached Definitions of Oil and Gas Reserves. Methods utilized in this report include extrapolation of historical production trends and analogy to similar producing properties.

Where sufficient production history and other data were available, reserves for producing properties were determined by extrapolation of historical production trends. Analogy to similar producing properties was used for those properties that lacked sufficient production history and other data to yield a definitive estimate of reserves. Subsequent production performance trends may cause the need for revisions to the estimates of reserves. In some cases on newer producing properties with limited production history, field chart readings may have been utilized to establish the estimated performance trends. Reserves projections based on analogy are subject to change due to subsequent changes in the analogous properties or subsequent production from the evaluated properties.

There are significant uncertainties inherent in estimating reserves, future rates of production, and the timing and amount of future costs. Oil and gas reserves estimates must be recognized as a subjective process that cannot be measured in an exact way and estimates of others might differ materially from those of Wright. The accuracy of any reserves estimate is a function of the quality of available data and of subjective interpretations and judgments. It should be emphasized that production data subsequent to the date of these estimates or changes in the analogous properties may warrant revisions of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and gas that ultimately are recovered.

Wright is an independent consulting firm and does not own any interests in the properties covered by this report. No employee, officer, or director of Wright is an employee, officer, or director of Atlas. Neither the employment of nor the compensation received by Wright is contingent upon the values assigned to the properties covered by this report.

For reporting purposes for AAI, Atlas requested summaries of total proved net reserves, cash flow and discounted cash flow (BTAX) for each subsidiary company of AAI that owns, directly or through their respective interests and various investment drilling partnerships managed by these companies, reserves included in this report that are attributed to AAI.. These companies consist of Atlas Resources, Inc.,


 

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 5


 

Viking Resources Corporation, Resource Energy, Inc., Atlas Energy, Inc., Atlas Noble Corp., REI-NY, Inc., and Atlas Energy Corporation. These summaries, by reserves category, are provided in the Summaries section of this report. Following is a summary, for each of these companies, of the total proved (PDP, PDNP, PDBP, and PUD) reserves in the evaluation, effective March 31, 2006.

 

COMPANY    Total Proved Net Reserves   

Cash Flow

(BTAX), M$

   10.00 PCT Cum.
Disc. (BTAX), M$
     Oil, Mbbl    Gas, Mmcf          

Atlas Resources, Inc.

   210.508    110,862.401    606,543.493    242,942.514

Viking Resources Corporation

   1,426.245    21,957.193    219,346.346    92,534.994

Resource Energy, Inc.

   284.050    12,313.374    74,590.214    35,714.055

Atlas Energy, Inc.

   110.821    6,887.174    53,513.664    22,540.556

Atlas Noble Corp.

   73.851    3,912.474    27,502.857    12,681.927

REI-NY, Inc.

   30.261    1,645.980    9,458.006    4,615.037

Atlas Energy Corporation

   2.239    531.468    3,032.663    1,343.670
                   

Total

   2,137.975    158,110.064    993,987.243    412,372.753
                   

Atlas has identified a pool designation for each property. Summaries for each pool group, by reserves category, are provided in the Summaries section of this report. There are four pool groups:

 

  1)   Clinton/Medina Formation—properties located in New York, Ohio and certain counties in Pennsylvania

 

  2)   Upper Devonian Sandstones—properties located in certain counties of Pennsylvania

 

  3)   Southern Appalachia Devonian Shale—Tennessee and West Virginia properties

 

  4)   Other Areas—Properties located in Kentucky and states other than Appalachia

The following table summarizes the results of the pool group summaries for AAI only:

 

POOL GROUP    Total Proved Net Reserves   

Cash Flow

(BTAX), M$

   10.00 PCT
Cum. Disc.
(BTAX), M$
     Oil, Mbbl    Gas, Mmcf          

Clinton/Medina Formation

   1,929.588    107,356.044    702,163.752    283,909.614

Upper Devonian Sandstones

   185.561    44,473.890    258,747.604    116,711.219

Southern Appalachia Devonian Shale

   2.616    5,799.798    29,214.994    9,975.234

Other

   20.210    480.332    3,860.893    1,776.686
                   

Total

   2,137.975    158,110.064    993,987.243    412,372.753
                   

Effective date gas prices were provided by Atlas. According to Atlas, the gas prices were based on certain contract language as applicable. A base NYMEX Henry Hub price of $7.180 per Mmbtu (million British thermal units) as of March 31, 2006 was used. This base gas price may have been adjusted, by lease, for energy content, transportation fees, and regional price differentials. According to Atlas, a small portion of gas sales contracts are based on a Columbia Gas Transmission (TCo) Index or Consolidated Natural Gas (CNG) Appalachia Index in effect as of March 31, 2006, as published in Gas Daily. Adjustments were made, as appropriate, based on certain contracts and agreements with the particular gas purchasers.


 

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Table of Contents

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 6


 

Where appropriate, fixed prices according to contracts were used until the contract expired. At the end of the contract period, the applicable March 31, 2006, base price was used. All contracts and agreements were interpreted by Atlas. Wright did not review any contracts or agreements.

For oil sold in Appalachia, the price was based upon the Ergon Oil Corporation posted price of $63.50 per barrel for oil at March 31, 2006, in New York, Ohio, and Pennsylvania, and $62.25 per barrel in Kentucky and West Virginia. In Tennessee, the posted price based on South Kentucky Purchasing, Inc. was $56.50 per barrel. For oil sold outside of Appalachia, the oil price was based on the West Texas Intermediate (WTI) price on March 31, 2006 of $66.25 per barrel.

No attempt has been made to account for oil or gas price fluctuations that have occurred in the market subsequent to the effective date of this report. After the effective date, prices were held constant for the life of the properties except where adjusted by contract. All oil and gas prices for this evaluation were provided by Atlas and were used in accordance with their instructions. It should be emphasized that with the current economic uncertainties, fluctuations in market conditions could significantly change the economics in this report.

Operating expenses were provided by Atlas and represented, when possible, the latest available estimated average of all recurring expenses that are billable to the working interest owners. These expenses included, but were not limited to, all direct operating expenses, field overhead costs, and any ad valorem taxes not deducted separately. Expenses for workovers, well stimulations, and other maintenance were not included in the operating expenses unless such work was expected on a recurring basis. Judgments for the exclusion of the nonrecurring expenses were made by Atlas. Any internal indirect overhead costs (general and administrative), which are not billable to the working interest owners, were not included. For new and developing properties where data were unavailable, operating expenses were estimated by Atlas based on analogy with similar properties. Operating costs were held constant for the life of the properties. Contractual transportation expenses were deducted where appropriate. It is Wright’s understanding that operating costs used in this report were based on those used in the Prior Report and were not updated during the six month interim period.

Standard state severance taxes have been deducted as appropriate. All taxes were based on current published rates and were used in accordance with the instructions of Atlas. According to Atlas, any ad valorem taxes not deducted separately were included in the operating expenses.

All capital costs for drilling and completion of wells and nonrecurring hook-up, workover, or operating costs have been deducted as applicable. These costs were provided by Atlas. No adjustments were made to account for the potential effect of inflation on these costs.

In accordance with the instructions of Atlas, neither salvage values nor abandonment costs were included in the projections of reserves and economics. It was assumed that any salvage value would be directly offset by the cost to abandon the property. No consideration was given in this report to potential environmental liabilities that may exist concerning the properties evaluated. There are no costs included in this evaluation for potential liability for restoration and to clean up damages, if any, caused by past or future operating practices.

Wright evaluated 478 PUD locations in Ohio, Pennsylvania, and Tennessee for this report. Reserves for these locations were evaluated for the Prior Report, and were assigned based on the mathematical average EUR’s of direct offsets to existing PDP wells where available, or based on the average EUR of


 

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Table of Contents

Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 7


 

certain PDP wells producing within the same formations in the same townships or areas. In certain townships or areas, the analogy method was not used because of an insufficient sample size. In these cases, analogy to an adjoining township or area was used. Wright’s PUD projections were formed using a generalized type curve for the township or area with initial starting rates and declines based on the reserves assigned. Atlas provided operating and transportation expenses as appropriate. According to Atlas, some PUD locations have been drilled since the Prior Report, as well as some locations not previously evaluated by Wright or included in the Prior Report. Any wells drilled since the Prior Report have been assigned to the PDNP or PDP reserves category as appropriate. Wright’s reserves projections may be based on test information and/or limited field production data. It should be noted that these projections may change significantly based on future performance. In the opinion of Wright there are a limited number of these new wells and they do not have a significant affect on the total value of the Total Proved Developed value. Wright has not reviewed or assigned any new PUD locations since the Prior Report in accordance with the instructions of Atlas.

Production in Ohio is primarily from the Clinton formation. In northwestern Pennsylvania, production is primarily from the Medina/Whirlpool. For wells in the remaining areas of Pennsylvania, production is primarily from the Upper Devonian formations. In the target sands, the quality of production is affected by the various reservoir characteristics, especially porosity and permeability. Hydraulic fracturing is typically used to increase well productivity.

The Clinton and Medina/Whirlpool Sandstones are generally considered to be blanket sands with a large aerial extent. Under circumstances in which a large number of wells (100 to 200 or more) are to be selectively drilled and monitored, in the opinion of Wright, the chances of obtaining a statistical average (“typical”) EUR could have a relatively high degree of certainty. The term “typical” is used herein to signify the average occurrence throughout the subject area as it relates to these properties.

Wright identified 166 PUD locations in Armstrong, Fayette, Greene, McKean, and Westmoreland Counties, Pennsylvania. For PUD’s in Armstrong, Fayette, Greene, and Westmoreland Counties, Atlas provided drilling costs of 255.751 M$ per location for Upper Devonian locations, and 142.423 M$ for shallow/natural locations. In McKean County, drilling costs of 99.371 M$ per location were provided by Atlas.

Wright assigned reserves to 278 PUD locations in Crawford, Lawrence, Mercer, and Venango Counties in Pennsylvania for which the primary target is the Medina/Whirlpool Sandstone. Drilling costs for these locations are 260.522 M$ according to Atlas.

Wright identified five PUD locations in Noble and Tuscarawas Counties in Ohio. The primary targets include the Clinton and Oriskany formations. Wright assigned reserves to the locations based on direct offset analogy and the average EUR’s assigned to the adjacent PDP wells. Drilling costs for these locations range from 195.154 M$ to 282.768 M$ per location.

The Tennessee properties are located in the Appalachian Plateau portion of northern Tennessee. This historically oil production area has seen recent activity targeting gas productive zones. The gas production in Tennessee is primarily from the Monteagle Limestone (Big Lime equivalent) and the Chattanooga Shale. In addition, a few wells produce from the deeper Trenton and Stones River formations. The Fort Payne, St. Louis, and Warsaw formations, which lie between the Monteagle


 

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Mr. Jeffrey C. Simmons

Atlas America, Inc.

July 12, 2006

Page 8


 

Limestone and the Chattanooga Shale, are considered secondary targets. Hydraulic fracturing is typically used to increase well productivity; however, natural production has been established in a few of the deeper wells.

There are 29 PUD locations assigned in Anderson and Scott Counties, Tennessee. Capital costs for these locations ranged from 282.777 M$ to 344.438 M$ per location.

In accordance with the instructions of Atlas, Wright used the following schedule for future drilling of identified PUD locations:

*Fiscal Year    No. of Wells
Scheduled to be
Drilled
   Total Net
Investment
(M$)

2006

   157    32,822.169

2007

   186    43,865.958

2008

   135    31,078.421
         

Total

   478    107,766.548
         

*   Fiscal year runs from October 1 through September 30

It should be especially noted that Atlas did not provide current capital costs or updated Authorization for Expenditures (AFE’s) with respect to the drilling of PUD locations. In accordance with the instructions of Atlas, Wright used the capital costs as contained in the Prior Report. It should be noted that in some areas, rig availability and increased drilling costs may influence the proposed drilling schedule and the total future investment required to realize the PUD reserves.

Atlas represented to Wright that it has or can generate the financial and operational capabilities to accomplish those projects evaluated by Wright that require capital expenditures, specifically the drilling of the PUD locations. Wright recommends that each location have proper spacing from a producing well to reduce the possibility of partial depletion of the reserves. According to Atlas, their assigned spacing has no material adverse effect on potential EUR.

This report should be considered in its entirety and should not be used for any purpose other than that outlined herein without the prior knowledge and express written authorization of an officer of Wright. It has been a pleasure to serve you by preparing this evaluation. All related data will be retained in our files and are available for your review.

 

Yours very truly,
Wright & Company, Inc.

 

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Table of Contents

LOGO

 

Until                     , 2007 (25 days after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.


Table of Contents

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution

Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE listing fee, the amounts set forth below are estimated:

 

Securities and Exchange Commission registration fee

   $ 16,345

NASD filing fee

     15,775

NYSE listing fee

     150,000

Printing and engraving expenses

     250,000

Legal fees and expenses

     650,000

Accounting fees and expenses

     225,000

Transfer agent and registrar

     3,500

Miscellaneous

     189,380
      

TOTAL

   $ 1,500,000
      

Item 14. Indemnification of Directors and Officers

The section of the prospectus entitled “Our Limited Liability Company Agreement—Indemnification” discloses that we will generally indemnify our directors, officers, managers and affiliates to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by this reference. Subject to any terms, conditions or restrictions set forth in the limited liability company agreement, Section 18-108 of the Delaware Limited Liability Act empowers a Delaware limited liability company to indemnify and hold harmless any member or other persons from and against all claims and demands whatsoever.

To the extent that the indemnification provisions of our limited liability company agreement purport to include indemnification for liabilities arising under the Securities Act of 1933, in the opinion of the SEC, such indemnification is contrary to public policy and is therefore unenforceable.

Item 15. Recent Sales of Unregistered Securities; Use of Proceeds from Registered Securities

In connection with our formation in June 2006, we issued to Atlas America, Inc., in exchange for $1,000, a membership interest representing the right to receive 100% of our distributions. The offering was exempt from registration under Section 4(2) of the Securities Act because the transaction did not involve a public offering.

 

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Table of Contents

Item 16. Exhibits and Financial Statements Schedules

(a)    Exhibits:

 

  1.1(1)   

Form of Underwriting Agreement

  3.1        Form of Amended and Restated Limited Liability Company Agreement of Atlas Energy Resources, LLC (included as Appendix A to the prospectus)
  3.2(1)   

Certificate of Formation of Atlas Energy Resources, LLC

  3.3(1)   

Limited Liability Company Agreement of Atlas Energy Resources, LLC dated June 23, 2006

  4.1       

Form of common unit certificate (included as Exhibit A to Appendix A to the prospectus)

  5.1(1)   

Opinion of Ledgewood, P.C. as to the legality of the securities being registered

  8.1(1)   

Opinion of Ledgewood, P.C. relating to tax matters

10.1(1)   

Form of Contribution and Assumption Agreement

10.2(1)   

Form of Omnibus Agreement

10.3(1)   

Form of Management Agreement

10.4(a)(1)   

Master Natural Gas Gathering Agreement, dated February 2, 2000, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc. and Viking Resources Corporation

10.4(b)(1)   

Natural Gas Gathering Agreement, dated January 1, 2002, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas Resources, Inc., Atlas Energy Group, Inc., Atlas Noble Corporation, Resource Energy, Inc. and Viking Resources Corporation

10.4(c)(1)   

Amendment to Master Natural Gas Gathering Agreement and Natural Gas Gathering Agreement, dated October 25, 2005, among Atlas Pipeline Partners, L.P., Atlas Pipeline Operating Partnership, L.P., Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Noble Corp. and Atlas Resources, Inc.

10.4(d)(1)   

Form of Amendment and Joinder to Gas Gathering Agreements

10.5(a)(1)   

Omnibus Agreement, dated February 2, 2000, among Atlas America, Inc., Resource Energy, Inc., Viking Resources Corporation, Atlas Pipeline Partnership, L.P., and Atlas Pipeline Partners, L.P.

10.5(b)(1)   

Form of Amendment and Joinder to Omnibus Agreement

10.6(1)   

Limited Liability Company Agreement of Atlas Energy Operating Company, LLC dated June 29, 2006.

10.7(1)   

Employment Agreement with Richard D. Weber

10.8(1)   

Form of Long-Term Incentive Plan

10.9(1)   

Drilling and Operating Agreement, dated September 15, 2004, between Atlas America, Inc. and Knox Energy, LLC

10.10(1)   

Form of Credit Agreement among Atlas Energy Operating Company, LLC, Wachovia Bank, National Association and the other parties thereto

10.11(1)   

Form of Services Agreement

10.12(a)(1)   

Gas Purchase Agreement, dated March 31, 1999, between Northeast Ohio Gas Marketing, Inc. and Atlas Energy Group, Inc.

10.12(b)(1)   

Amendment to Gas Purchase Agreement, dated February 1, 2001, between FirstEnergy Services Corp., an assign of Northeast Ohio Gas Marketing, Inc., Atlas Energy Group, Inc. and Resource Energy Inc.

10.12(c)(1)   

Second Amendment to Base Gas Purchase Agreement, dated July 16, 2003, between FirstEnergy Solutions Corp. and Atlas Energy Group, Inc., Atlas Resources, Inc. and Resource Energy, Inc.

10.12(d)(1)   

Assignment and Novation of Transactions, dated April 1, 2005, between FirstEnergy Solutions Corp., Amerada Hess Corporation and the Atlas parties named therein.

21.1(1)   

Subsidiaries of Atlas Energy Resources, LLC

 

II-2


Table of Contents
23.1        

Consent of Grant Thornton LLP

23.2(1)   

Consent of Wright & Company, Inc.

23.3        

Consent of Ledgewood, P.C. (contained in Exhibits 5.1 and 8.1)

24.1(1)   

Powers of Attorney

99.1(1)   

Consents of Director Nominees


(1)   Previously filed.

(b)    Financial Statement Schedules

All financial statement schedules are omitted because the information is not required, is not material or is otherwise included in the financial statements or related notes thereto.

Item 17. Undertakings

The undersigned registrant hereby undertakes to provide to the Underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the Underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

 

·   For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

 

·   For purposes of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The registrant undertakes to send to each unitholder at least on an annual basis a detailed statement of any transactions with the manager or its affiliates, and of fees, commissions, compensation and other benefits paid, or accrued to the manager or its affiliates for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the registrant.

 

II-3


Table of Contents

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Moon Township, Pennsylvania, on December 5, 2006.

 

ATLAS ENERGY RESOURCES, LLC

By:

  /S/    EDWARD E. COHEN         
 

Edward E. Cohen

Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed below by the following persons in the capacities and on the dates indicated.

 

/S/    MATTHEW A. JONES        

Matthew A. Jones

   Chief Financial Officer and
Director and as
attorney in fact for:
Edward E. Cohen, Chairman and
      Chief Executive Officer
Jonathan Z. Cohen,
      Vice Chairman
Richard D. Weber, President,
      Chief Operating Officer
      and Director
  December 5, 2006

/S/    NANCY J. MCGURK

Nancy J. McGurk

  

Chief Accounting Officer

  December 5, 2006

 

II-4


Dates Referenced Herein   and   Documents Incorporated by Reference

This ‘S-1/A’ Filing    Date    Other Filings
12/31/0910-K
6/30/0910-Q
3/31/0910-Q
9/30/0810-Q
4/17/08424B5,  8-K
1/1/08
12/31/0710-K
12/30/07
10/31/07
9/30/0710-Q
6/30/0710-Q
3/31/0710-Q
3/14/07
1/1/07
12/31/0610-K
Filed on:12/5/06
11/20/06
11/10/06
11/1/06S-1/A
9/30/06
7/14/06
7/12/06
6/29/06
6/23/06
4/17/06
4/5/06
3/31/06
1/1/06
12/31/05
12/15/05
10/28/05
10/25/05
10/1/05
9/30/05
4/4/05
4/1/05
1/1/05
12/31/04
10/1/04
9/30/04
9/15/04
10/1/03
9/30/03
7/16/03
10/1/02
9/30/02
1/1/02
9/30/01
2/1/01
1/1/01
9/27/00
2/2/00
12/1/99
10/1/99
3/31/99
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