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Atlas Energy Resources, LLC · IPO:  S-1/A · On 11/1/06

Filed On 11/1/06, 2:44pm ET   ·   Accession Number 1193125-6-220473   ·   SEC File 333-136094

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

11/01/06  Atlas Energy Resources, LLC       S-1/A                 15:4.1M                                   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       Amendment No. 2 to Form S-1 Registration Statement  HTML   2.87M 
 2: EX-1.1      Form of Underwriting Agreement                      HTML    236K 
 3: EX-8.1      Opinion of Ledgewood, P.C.                          HTML     12K 
 4: EX-10.1     Form of Contribution and Assumption Agreement       HTML     67K 
 5: EX-10.2     Form of Omnibus Agreement                           HTML     28K 
 6: EX-10.3     Form of Management Agreement                        HTML     77K 
 7: EX-10.4.(A)  Master Natural Gas Gathering Agreement             HTML     61K 
 8: EX-10.4.(B)  Natural Gas Gathering Agreement                    HTML     55K 
 9: EX-10.4.(C)  Amendment to Mater Natural Gas Gathering           HTML     18K 
                          Agreement                                              
10: EX-10.4.(D)  Form of Amendment and Joinder to Gas Gathering     HTML     27K 
                          Agreement                                              
11: EX-10.5.(A)  Ominbus Agreement, Dated February 2, 2000          HTML     41K 
12: EX-10.5.(B)  Form of Amendment and Joinder to Omnibus           HTML     24K 
                          Agreement                                              
13: EX-10.8     Form of Long-Term Incentive Plan                    HTML     43K 
14: EX-10.9     Drilling and Operating Agreement                    HTML    152K 
15: EX-23.1     Consent of Grant Thornton LLP                       HTML      8K 


S-1/A   —   Amendment No. 2 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
"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 June 30, 2006
"Unaudited Pro Forma Combined Statement of Income for the nine months ended June 30, 2006
"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 and 2005 and June 30, 2006
"Combined Statements of Income for the years ended September 30 2003, 2004 and 2005 and nine months ended June 30, 2005 and 2006
"Combined Statements of Comprehensive Income for the years ended September 30 2003, 2004 and 2005 and nine months ended June 30, 2005 and 2006
"Combined Statements of Combined Equity for the years ended September 30 2003, 2004 and 2005 and nine months ended June 30, 2006
"Combined Statements of Cash Flows for the year ended September 30, 2003, 2004 and 2005 and the nine months ended June 30, 2005 and 2006
"Notes to Combined Financial Statements
"Balance Sheet as of July 14, 2006
"Note to Balance Sheet
"Appendix B -- Glossary of Terms

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  Amendment No. 2 to Form S-1 Registration Statement  
Table of Contents

As filed with the Securities and Exchange Commission on November 1, 2006

Registration No. 333-136094

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT

No. 2 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

Ledgewood

  Catherine S. Gallagher

1900 Market Street

  Vinson & Elkins L.L.P.

Philadelphia, Pennsylvania 19103

  1001 Fannin Street

(215) 731-9450

  Houston, Texas 77002
  (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   November 1, 2006

6,075,000 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 $            and $            per common unit.

We have applied to list our common units 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 $16.28 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.

The underwriters may also purchase up to an additional 911,250 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

The date of this prospectus is             , 2006


Table of Contents

TABLE OF CONTENTS


 

PROSPECTUS SUMMARY

   1

Atlas Energy Resources

   1

Business Strategy

   5

Competitive Strengths

   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

   50

Distributions of Available Cash from Operating Surplus

   54

Management Incentive Interests

   54

Percentage Allocations of Available Cash from Operating Surplus

   56

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

   88

Cash Flows

   90

Changes in Prices and Inflation

   91

Environmental Regulation

   92

Dividends

   92

Contractual Obligations and Commercial Commitments

   92

Critical Accounting Policies

   93

Recently Issued Financial Accounting Standards

   95

Quantitative and Qualitative Disclosures About Market Risk

   96

BUSINESS

   99

Overview

   99

Business Strategy

   100

Competitive Strengths

   101

Appalachian Basin Overview

   103

Gas and Oil Production

   103

Productive Wells

   104

Developed and Undeveloped Acreage

   105

Drilling Activity

   106

Investment Partnerships

   106

Tennessee Joint Venture Agreement

   107

Natural Gas and Oil Reserves

   108

Natural Gas Sales

   110

Crude Oil Sales

   111

Dismantlement, Restoration, Reclamation and Abandonment Costs

   111

Natural Gas Hedging

   111

Natural Gas Gathering

   112

Availability of Oil Field Services

   114

 


 

i


Table of Contents

 

Major Customers

   114

Competition

   114

Markets

   115

Natural Gas and Oil Leases

   115

Seasonal Nature of Business

   115

Environmental Matters and Regulation

   116

Other Regulation of the Natural Gas and Oil Industry

   119

Litigation

   120

MANAGEMENT

   121

Our Board of Directors and Executive Officers

   121

Board Committees

   123

Governance Matters

   124

Compensation Committee Interlocks and Insider Participation

   125

Compensation of Directors

   125

Executive Compensation

   125

Employment Agreement

   125

Our Manager

   126

Officers of Our Manager

   127

Other Significant Employees

   128

Compensation of Our Manager’s Directors

   128

Reimbursement of Expenses of Our Manager and its Affiliates

   128

Atlas Energy Resources Long-Term Incentive Plan

   129

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

   131

Distributions and Payments to our Manager and Atlas America

   131

Agreements Governing the Transactions

   132

CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

   137

Conflicts of Interest

   137

Fiduciary Duties

   139

SECURITY OWNERSHIP OF PRINCIPAL BENEFICIAL OWNERS AND MANAGEMENT

   140

DESCRIPTION OF THE COMMON UNITS

   141

The Common Units

   141

Transfer Agent and Registrar

   141

Transfer of Common Units

   141

OUR LIMITED LIABILITY COMPANY AGREEMENT

   143

Organization

   143

Purpose

   143

Fiduciary Duties

   143

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

   143

Capital Contributions

   144

Limited Liability

   144

Voting Rights

   144

Elimination of Special Voting Rights of Class A Units

   145

Issuance of Additional Securities

   145

Election of Members of Our Board of Directors

   146

Amendment of Our Limited Liability Company Agreement

   146

Merger, Sale or Other Disposition of Assets

   148

Termination and Dissolution

   148

Liquidation and Distribution of Proceeds

   148

Anti-Takeover Provisions

   149

Limited Call Right

   150

Meetings; Voting

   150

Non-Citizen Assignees; Redemption

   151

Indemnification

   151

Books and Reports

   152

Right To Inspect Our Books and Records

   152

Registration Rights

   153

UNITS ELIGIBLE FOR FUTURE SALE

   154

MATERIAL TAX CONSEQUENCES

   155

Partnership Status

   156

Unitholder Status

   157

Tax Consequences of Unit Ownership

   158

Tax Treatment of Operations

   163

Disposition of Common Units

   167

Uniformity of Common Units

   169

Tax-Exempt Organizations and Other Investors

   170

Administrative Matters

   171

State, Local and Other Tax Considerations

   173

 


 

ii


Table of Contents

 

UNDERWRITING

   174

LEGAL MATTERS

   179

ENGINEERS

   179

EXPERTS

   179

WHERE YOU CAN FIND MORE INFORMATION

   179

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. 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 June 30, 2006, our principal assets consisted of:

 

Ø   working interests in 6,252 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 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

 

1


Table of Contents
Ø   approximately 543,400 gross (491,000 net) acres, primarily in the Appalachian Basin, over half of which, or 286,700 gross (273,200 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 209,000 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 June 30, 2006, we produced 25,110 Mcfe/d net to our interest in the production of our investment partnerships and including our direct interests in producing wells, which 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 10th most active operator in the United States based on well starts from January 2006 to August 2006. As of June 30, 2006, we had identified approximately 500 proved undeveloped drilling locations and over 2,400 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 $200 to $362, 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,    

Nine months

ended

June 30,
2006

 
     2001     2002     2003     2004     2005    
   (unaudited)                       (unaudited)  

Segment results (in thousands):

            

Revenues:

            

Gas and oil production

   $ 36,681     $ 28,916     $ 38,639     $ 48,526     $ 63,499     $ 68,894  

Partnership management:

            

Well construction and completion

     43,464       55,736       52,879       86,880       134,338       126,833  

Administration and oversight

     3,632       4,805       5,090       9,874       13,223       8,098  

Well services

     7,403       7,585       7,635       8,430       9,552       8,713  

Gathering(1)

     3,448       3,497       3,898       4,191       4,359       5,981  
                                                

Total partnership management

     57,947       71,623       69,502       109,375       161,472       149,625  
                                                

Total revenues

     94,628       100,539       108,141       157,901       224,971       218,519  

Segment margin(2):

            

Gas and oil production

     28,849       20,652       30,153       39,688       54,429       58,776  

Partnership management:

            

Well construction and completion

     6,862       7,293       6,897       11,332       17,522       16,545  

Administration and oversight

     3,632       4,805       5,090       9,874       13,223       8,098  

Well services

     4,443       3,838       3,862       4,032       4,385       3,438  

Gathering(1)

     (9,795 )     (7,307 )     (10,695 )     (13,051 )     (17,622 )     (17,870 )
                                                

Total partnership management

     5,142       8,629       5,154       12,187       17,508       10,211  
                                                

Total segment margin(2)

     33,991       29,281       35,307       51,875       71,937       68,987  

Investment partnership and reserves data:

            

Funds raised (in millions)

   $ 44.8     $ 41.1     $ 66.1     $ 107.7     $ 148.7     $ 166.8  

Gross wells completed(3)

     258       252       296       505       662       513  

Developed acres:

            

Gross

     252,346       265,000       225,800       233,800       245,000       256,800  

Net

     189,624       194,000       188,500       197,200       206,700       217,800  

Undeveloped acres:

            

Gross

     244,124       223,000       205,400       249,800       267,300       286,700  

Net

     219,482       213,000       190,500       236,000       253,900       273,200  

Total acres:

            

Gross

     496,470       488,000       431,200       483,600       512,300       543,400  

Net

     409,106       407,000       379,000       433,200       460,600       491,000  

Total reserves managed (Bcfe) (end of period)

     303.6       317.1       332.2       365.1       401.1       397.5 (4)

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

     129.0       134.5       144.4       155.8       171.6       170.9 (4)

% natural gas

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

% proved developed(5)

     70.3 %     70.7 %     68.3 %     69.6 %     68.5 %     70.2 %(4)

Production (Mmcfe/d)(6)

     20.3       22.3       21.7       22.9       23.5       25.1  

Reserves to production ratio (years)

     17.4 x     16.5 x     18.2 x     18.6 x     20.0 x     18.3 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 assume our obligation to pay gathering fees to Atlas Pipeline. We will be obligated to pay the gathering fees we receive from

 

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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 June 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 June 30, 2006 of 25.6 Mmcfe/d and our proved reserves at March 31, 2006.

Gas and oil production

As of June 30, 2006, we owned interests in 6,884 gross wells, principally in the Appalachian Basin, of which we operated 5,833. On average during the quarter ended June 30, 2006, gross production from our wells was 81.2 MMcfe/d, or approximately 11.8 Mcfe/d per well. Over the past three fiscal years we have drilled 1,463 gross (565 net) wells, 98% of which were successful in producing natural gas in commercial quantities, including 662 gross wells in the fiscal year ended September 30, 2005, 97% of which were successful. In the nine months ended June 30, 2006, we drilled 513 gross (170 net) wells, over 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 209,000 acres owned by Knox Energy. As of June 30, 2006, we had drilled 103 net wells under this agreement. As of June 30, 2006, we had identified approximately 500 proved undeveloped drilling locations and over 2,400 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 fiscal year ended September 30, 2005, the average premium over NYMEX for natural gas delivered to our primary delivery points in the Appalachian Basin was $0.37 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 fiscal 2006 and $148.7 million in fiscal 2005. 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.

 

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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.

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 June 30, 2006, we had financial hedges and physical hedges in place for approximately 65% of our expected production for the twelve months ending September 30, 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 a leading sponsor 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.

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 the stock of 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 and retention of $5.5 million for working capital, to Atlas America as reimbursement of capital expenditures incurred by it on our behalf and partial consideration for its contribution of assets to us.

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.”

 

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

 

Ø   Atlas America will own 29,150,000 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 719,898 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 6,075,000 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 28,238,750 common units, or approximately 78.5% of our membership interests, and the ownership interest of the public unitholders will increase to 6,986,250 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

6,075,000 common units; 6,986,250 common units if the underwriters exercise their over-allotment option in full.

 

Units outstanding after this offering

35,275,000 common units; and 719,898 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)    $ 111.5 million
      

Uses of funds:

  
Distribution to Atlas America(1)(2)    $ 106.0 million

Working capital

   $ 5.5 million
      
   $ 111.5 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 $0.40 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 $0.46 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

   $0.40    2.0 %   98.0 %   0.0 %
First Target Distribution per unit    above $0.40
up to $0.46
   2.0 %   98.0 %   0.0 %
Second Target Distribution per unit    above $0.46
up to $0.56
   2.0 %   83.0 %   15.0 %
After that    above $0.56    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 $0.56, 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 $0.40 on all of the common units and Class A units for each quarter for the twelve months ending September 30, 2007. If we had completed this offering and the related transactions on October 1, 2004, the amount of pro forma available cash generated during the fiscal year ended September 30, 2005 would have been insufficient by approximately $45.1 million to pay the IQD on all of our common units and

 

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Class A units. If we had completed this offering and the related transactions on July 1, 2005, the amount of pro forma available cash generated during the twelve months ended June 30, 2006 would have been insufficient by approximately $39.9 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 82.6% 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

 

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our business affairs in conformity with the policies that are approved and monitored by our board of 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,             , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be less than             % 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

We have applied to list our common units 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 for the years ended September 30, 2003, 2004 and 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 nine months ended June 30, 2005 and 2006 and the balance sheet information as of June 30, 2006 from Atlas America E & P Operations’ unaudited financial statements included in this prospectus.

The summary pro forma financial data for the year ended September 30, 2005 and nine months ended June 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 June 30, 2006, in the case of the pro forma balance sheet, or as of October 1, 2004, in the case of the pro forma statements of income. 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 September 30,     Nine months ended
June 30,
    Year ended
September 30,
2005
    Nine months
ended June 30,
2006
 
     2003     2004     2005     2005     2006      
                      (unaudited)     (unaudited)  
    (in thousands)  

Income statement data:

             

Revenues:

             

Gas and oil production

  $ 38,639     $ 48,526     $ 63,499     $ 44,669     $ 68,894     $ 63,499     $ 68,894  

Partnership management:

             

Well construction and completion

    52,879       86,880       134,338       98,758       126,833       134,338       126,833  

Administration and oversight

    5,090       9,874       13,223       7,315       8,098       13,223       8,098  

Well services

    7,635       8,430       9,552       7,020       8,713       9,552       8,713  

Gathering(1)

    3,898       4,191       4,359       3,186       5,981       4,359       5,981  
                                                       

Total revenues

    108,141       157,901       224,971       160,948       218,519       224,971       218,519  

Direct costs:

             

Gas and oil production and exploration(1)

    8,486       8,838       9,070       6,667       10,118       9,070       10,118  

Partnership management:

             

Well construction and completion

    45,982       75,548       116,816       85,876       110,288       116,816       110,288  

Administration and oversight

    —         —         —         —         —         —         —    

Well services

    3,773       4,398       5,167       3,800       5,275       5,167       5,275  

Gathering(1)

    29       53       52       37       176       —         —    

Gathering fee—Atlas Pipeline(1)

    14,564       17,189       21,929       15,672       23,675       4,359       5,981  
                                                       

Total direct costs

    72,834       106,026       153,034       112,052       149,532       135,412       131,662  

Segment margin:

             

Gas and oil production

    30,153       39,688       54,429       38,002       58,776       54,429       58,776  

Partnership management:

             

Well construction and completion

    6,897       11,332       17,522       12,882       16,545       17,522       16,545  

Administration and oversight

    5,090       9,874       13,223       7,315       8,098       13,223       8,098  

Well services

    3,862       4,032       4,385       3,220       3,438       4,385       3,438  

Gathering

    (10,695 )     (13,051 )     (17,622 )     (12,523 )     (17,870 )     —         —    
                                                       

Total segment margin

    35,307       51,875       71,937       48,896       68,987       89,559       86,857  

Other operating costs:

             

General and administrative expense

    (8,390 )     (11,637 )     (15,930 )     (7,525 )     (14,592 )     (16,697 )     (14,979 )

Net expense reimbursement—affiliate

    (1,400 )     (1,050 )     (602 )     (602 )     (859 )     (602 )     (859 )

Depreciation, depletion and amortization

    (9,938 )     (12,064 )     (14,061 )     (9,762 )     (15,103 )     (14,061 )     (15,103 )
                                                       

Operating income

    15,579       27,124       41,344       31,007       38,433       58,199       55,916  

Other income (expenses):

             

Interest income

    251       250       317       220       160       317       160  

Interest expense

    —         —         —         —         —         (735 )     (630 )

Other—net

    107       194       (238 )     (129 )     254       (238 )     254  
                                                       
    358       444       79       91       414       (656 )     (216 )
                                                       

Net income before taxes

  $ 15,937     $ 27,568     $ 41,423     $ 31,098     $ 38,847     $ 57,543     $ 55,700  
                                                       

Other financial information (unaudited):

             

EBITDA

  $ 25,875     $ 39,632     $ 55,484     $ 40,860     $ 53,950     $ 72,339     $ 71,433  

 

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     Predecessor historical     Atlas
Energy
Resources
pro forma
 
     As of and for the years ended
September 30,
    As of and for the
nine months ended
June 30,
   
      2003     2004     2005     2005     2006     June 30,
2006
 
                       (unaudited)     (unaudited)  
     (in thousands)        

Cash flow data:

            

Cash provided by operating activities

   $ 20,365     $ 42,523     $ 65,444     $ 48,377     $ 56,885    

Cash used in investing activities

     (22,112 )     (32,709 )     (59,050 )     (42,689 )     (54,691 )  

Cash provided by (used in) financing activities

     34       (14,916 )     (320 )     (325 )     86    

Capital expenditures

     22,607       33,252       59,124       42,775       54,473    

Balance sheet data (at period end):

            

Total assets

   $ 178,451     $ 198,454     $ 270,402     $ 245,421     $ 351,568     $ 357,068  

Liabilities associated with drilling contracts

     22,157       29,375       60,971       55,627       88,810       88,810  

Advances from affiliates

     34,776       30,008       13,897       16,163       4,994       —    

Long term debt, including current portion

     194       420       81       95       112       5,106 (2)

Total debt

     34,970       30,428       13,978       16,258       5,106       5,106  

Combined equity

     102,031       109,461       146,142       136,113       169,238       174,738  

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

 

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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

September 30,

   

Atlas Energy
Resources at
March 31,

2006

 
      
          2004             2005        

Reserve data:

      

Estimated net proved reserves:

      

Natural gas (Bcf)

     142.1       158.0       158.1  

Oil (MMBbls)

     2.3       2.3       2.1  

Total (Bcfe)

     155.8       171.6       170.9  

Proved developed (Bcfe)

     108.5       117.5       120.0  

Proved undeveloped (Bcfe)

     47.3       54.1       50.9  

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

     69.6 %     68.5 %     70.2 %

PV-10 value (in millions)(2)

   $ 320.4     $ 845.7     $ 412.4  

Standardized measure (in millions)(2)

   $ 233.0     $ 606.7     $ 412.4  

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

      

Natural gas—per Mcf

   $ 6.91     $ 14.75     $ 8.04  

Oil—per Bbl

   $ 46.00     $ 63.29     $ 63.52  

 

     Years ended
September 30,
   Nine months ended
June 30,
      2004    2005    2005    2006

Net production:

           

Total production (Mmcfe)

     8,371      8,573      6,253      6,845

Average daily production (Mcfe/d)

     22,875      23,490      22,903      25,073

Average natural gas sales prices per Mcf:

           

Average sales prices (including hedges)

   $ 5.84    $ 7.26    $ 7.03    $ 10.03

Average sales prices (excluding hedges)

   $ 5.84    $ 7.26    $ 7.03    $ 9.36

Average oil sales prices per Bbl:

           

Average sales prices

   $ 32.85    $ 50.91    $ 47.57    $ 61.53

Average unit costs per Mcfe:

           

Production costs

   $ 0.87    $ 0.95    $ 0.94    $ 1.36

Depletion

   $ 1.22    $ 1.42    $ 1.34    $ 2.00

(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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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   Atlas Energy Resources pro
forma
    Years ended September 30,  

Nine months
ended

June 30,

  Year ended
September 30,
 

Nine months

ended

June 30,

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

Net income before taxes

  $ 13,532   $ 11,197   $ 15,937   $ 27,568   $ 41,423   $ 31,098   $ 38,847   $ 57,543   $ 55,700

Plus interest expense

    —       —       —       —       —       —       —       735     630

Plus depreciation, depletion and amortization

    9,594     9,409     9,938     12,064     14,061     9,762     15,103     14,061     15,103
                                                     

EBITDA

  $ 23,126   $ 20,606   $ 25,875   $ 39,632   $ 55,484   $ 40,860   $ 53,950   $ 72,339   $ 71,433
                                                     

 

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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,    

Nine months

ended

June 30,

   

Year ended
September 30,

2005

   

Nine months
ended
June 30,

2006

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

Segment margin:

                 

Gas and oil production

  $ 28,849     $ 20,652     $ 30,153     $ 39,688     $ 54,429     $ 38,002     $ 58,776     $ 54,429     $ 58,776  

Partnership management:

                 

Well construction and completion

    6,862       7,293       6,897       11,332       17,522       12,882       16,545       17,522       16,545  

Administration and oversight

    3,632       4,805       5,090       9,874       13,223       7,315       8,098       13,223       8,098  

Well services

    4,443       3,838       3,862       4,032       4,385       3,220       3,438       4,385       3,438  

Gathering

    (9,795 )     (7,307 )     (10,695 )     (13,051 )     (17,622 )     (12,523 )     (17,870 )     —         —    
                                                                       

Total partnership management

    5,142       8,629       5,154       12,187       17,508       10,894       10,211       35,130       28,081  
                                                                       

Total segment margin

    33,991       29,281       35,307       51,875       71,937       48,896       68,987       89,559       86,857  

Less segment depreciation, depletion and amortization

    (8,040 )     (9,154 )     (9,340 )     (11,326 )     (13,611 )     (9,414 )     (14,791 )     (12,288 )     (14,791 )
                                                                       

Gross margin

  $ 25,951     $ 20,127     $ 25,967     $ 40,549     $ 58,326     $ 39,482     $ 54,196     $ 77,271     $ 72,066  
                                                                       

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.

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

 

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attributable to our proved reserves before taking into account future corporate income taxes for which we will not liable. Our PV-10 values as of 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. 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
September 30,
   

Atlas Energy
Resources
as of
March 31, 2006

 

      2004     2005    

PV-10 value

   $ 320.4     $ 845.7     $ 412.4

Income tax effect

     (87.4 )     (239.0 )     0
                      

Standardized measure

   $ 233.0     $ 606.7     $ 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 $57.6 million. If we had completed the transactions contemplated in this prospectus on October 1, 2004, pro forma available cash generated during the fiscal year ended September 30, 2005 would have been approximately $12.5 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 July 1, 2005, pro forma available cash generated during the twelve months ended June 30, 2006 would have been approximately $17.7 million, which would have been sufficient to allow us to pay approximately 31% 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 September 30, 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

 


 

25


Table of Contents

Risk factors


 

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;

 

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 six months ended June 30, 2006, the NYMEX Henry Hub natural gas index price ranged from a high of $9.92 per MMBtu to a low of $5.68 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $74.70 per Bbl to a low of $57.35 per Bbl.

At June 30, 2006, we owned interests in 6,884 gross wells that produced, on average during the quarter ended June 30, 2006, 81.2 MMcfe/d, or approximately 11.8 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

 


 

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reserves and economically finding or acquiring additional recoverable reserves. Our ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on our generating sufficient cash flow from operations and other sources of capital, 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.

 


 

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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, 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 September 30, 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

 


 

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borrowings. In particular, our forecast of cash available for distribution for the twelve month period ending September 30, 2007 assumes that we will raise $270.0 million from third parties through our investment partnerships. This amount of capital is significantly more than the $199.8 million we raised during fiscal 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;

 


 

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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

 

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 September 30, 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. For example, the Pennsylvania Bureau of Oil and Gas Management estimates that there were 747 well operators bonded in Pennsylvania, one of our core operating areas, in 2005. 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. 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 investment partnerships for gathering services. If Atlas America defaulted on its obligation to us under the assumption agreement to pay gathering

 


 

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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 December 31, 2008, 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 13% of our total revenues, and during the nine months ended June 30, 2006, Hess Corporation accounted for 11% 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 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

 


 

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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 June 30, 2006, we had identified approximately 500 proved undeveloped drilling locations and over 2,400 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 2,400 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 869 gross wells on behalf of investment partnerships during the twelve months ending September 30, 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.

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

Leases covering approximately 16,500 of our 491,000 net acres, or 3.4%, are scheduled to expire on or before June 30, 2007. If we are unable to renew these leases, or any leases scheduled for expiration

 


 

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beyond June 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 92 investment partnerships and will be the managing general partner of new investment partnerships that we sponsor. As a general partner, we are contingently liable for the obligations of these partnerships to the extent that partnership assets or insurance proceeds are insufficient. We have agreed to indemnify each investor partner in our investment partnerships from any liability that exceeds such partner’s share of the investment partnership’s assets. 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 82.6% 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.

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.

 

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 $16.28 per common unit.

The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $3.72 per common unit. Based on the assumed initial public offering price, you will incur immediate and substantial dilution of $16.28 per common unit. Please read “Dilution.”

 


 

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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;

 

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

 


 

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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 6,075,000 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.

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

 


 

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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 29,150,000 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 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

 


 

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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.

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.

 


 

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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 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.

 


 

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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.

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

 


 

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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)

   $ 111.5
      

Uses of funds (in millions):

  

Distribution to Atlas America(1)(2)

   $ 106.0

Working capital

     5.5
      
   $ 111.5
      

(1)   We estimate that we will receive net proceeds of approximately $111.5 million from the sale of the 6,075,000 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 $8.5 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 29,150,000 common units to 28,238,750 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 June 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 June 30, 2006
      Historical    Pro forma
     (in thousands)

Cash and cash equivalents

   $ 8,526    $ 12,526
             

Credit facility(1)

     —        4,994

Advances from affiliates

     4,994      —  

Other debt

     112      112
             

Total debt

     5,106      5,106

Equity

     

Combined equity

     169,238      —  

Held by public:

     

Common units

     —        111,495

Held by Atlas America and affiliates(2):

     

Common units

     —        59,748

Held by our manager:

     

Class A units

     —        3,495
             

Total equity

     169,238      174,738
             

Total capitalization

   $ 174,344    $ 179,844
             

(1)   Reflects pro forma borrowings of $5.0 million under our proposed credit facility to repay the advances from affiliates.
(2)   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 June 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 $133.9 million or $3.72 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)

   $ 4.29    

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

   $ (0.57 )  
          

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

 

  $ 3.72
        

Immediate dilution in net tangible book value per common unit

 

  $ 16.28
        

(1)   Determined by dividing the total number of common units (29,200,000) and Class A units (719,898) 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 (35,275,000) and Class A units (719,898) 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)

   29,869,898    83.0 %   $ 63,243    34 %

Richard D. Weber(2)

   50,000    0.1 %     —      —    

New investors

   6,075,000    16.9 %     121,500    66 %
                        

Total

   35,994,898    100 %   $ 184,743    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 June 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

   $ 169,238  

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

     (105,995 )
        

Total consideration

   $ 63,243  
        

 

(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 $0.40 per unit, or $1.60 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 September 30, 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.

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.

 


 

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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 and interest paid on debt 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 from the earlier to occur of the commencement of construction or such financing until the earlier to occur of the date the 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 capital transactions; or

 

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

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

 


 

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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 such financing 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 from the earlier to occur of the commencement of construction or the financing of the replacement asset until 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 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.”

 


 

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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 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.

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

 


 

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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 $0.46 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 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.

 


 

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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 $0.56 (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 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

 


 

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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

   $0.40    2 %   98 %   0 %

First Target Distribution

   above $0.40
up to $0.46
   2 %   98 %   0 %

Second Target Distribution*

   above $0.46
up to $0.56
   2 %   83 %   15 %

After that*

   above $0.56    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 and the nine months ended June 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 $0.40 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 $0.40 per unit per quarter) and for four full quarters (at the initial rate of $1.60 per unit on an annualized basis):

 

          Initial quarterly distribution
      Number of
units
   One quarter    Four quarters

Common units

   35,275,000    $ 14,110,000    $ 56,440,000

Class A units

   719,898      287,959      1,151,837
                  

Total

   35,994,898    $ 14,397,959    $ 57,591,837
                  

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 September 30, 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 September 30, 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 fiscal year ended September 30, 2005 and the twelve months ended June 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 September 30, 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 September 30, 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 $0.40 per unit on all outstanding common units and Class A units for each full calendar quarter in the twelve-month period ending September 30, 2007.

ESTIMATED CASH AVAILABLE FOR DISTRIBUTION

In order to pay the IQD to our unitholders of $0.40 per unit per quarter for the twelve month period ending September 30, 2007, our available cash for distribution must be at least approximately $57.6 million over that period. We estimate that our EBITDA for the twelve-month period ending September 30, 2007 must be approximately $94.9 million in order to generate cash available for distribution to the holders of our common units and Class A units of approximately $57.6 million over that period. We refer to this amount as “Estimated EBITDA.” Estimated EBITDA is intended to be an indicator or benchmark of the amount management considers to be the amount of EBITDA necessary to generate sufficient available cash for us to make cash distributions to our unitholders at our IQD rate of $0.40 per unit per quarter (or $1.60 per common unit and Class A unit per year).

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 September 30, 2007, we have included amounts for estimated maintenance and investment capital expenditures, as well as average borrowings of $25.9 million for the period to fund a portion of investment capital expenditures. If we do not finance such expenditures with borrowings or issuances of 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

 


 

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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 September 30, 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 September 30, 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 $94.9 million necessary for us to have sufficient cash available for distribution to pay distributions at the IQD rate on all outstanding common units and Class A units for each quarter for the twelve-month period ending September 30, 2007. 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 September 30, 2007. The assumptions we disclose below are those that we believe are significant to our ability to generate the necessary 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 September 30, 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 September 30, 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 September 30, 2007, assuming that the offering was consummated on October 1, 2006. We explain each of the adjustments presented below in the footnotes to the table. All of the amounts for the twelve-month period ending September 30, 2007 in the table and footnotes are estimates.

Estimated cash available for distribution

 

     

Twelve months ending

September 30, 2007

 
     (in thousands, except per
unit data and ratios)
 

Estimated EBITDA(a)

   $ 94,905  

Less:

  

Cash interest expense(b)

     (2,313 )

Estimated maintenance capital expenditures(c)

     (35,000 )

Investment capital expenditures(d)

     (47,897 )

Plus:

  

Borrowings and other sources for investment capital expenditures(e)

     47,897  

Excess proceeds from initial public offering available for distribution(f)

     5,500  
        

Estimated cash available for distribution

   $ 63,092  
        

Expected cash distributions

  

Annualized IQD per unit(g)

   $ 1.60  
        

Distributions to our common unitholders

   $ 56,440  

Distributions to our Class A unitholder

     1,152  
        

Total distributions to our unitholders(g)

   $ 57,592  
        

Debt covenant ratios

  

Funded debt/EBITDA ratio(h)

     0.3x  

Interest coverage ratio(h)

     41.0x  

Current ratio(h)

     1.2x  

 


 

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(a)   As reflected in the table below, to generate our Estimated EBITDA for the twelve months ending September 30, 2007, we have assumed the following regarding our operations, revenues and expenses:

 

Gas and oil production key assumptions:

  

Net natural gas production volume(1)

   9,328,852 Mcf  

Average natural gas price on hedged volumes(2)

   $9.16 per Mcf  

Average natural gas price on unhedged volumes(2)

   $8.17 per Mcf  

Percentage of net gas production assumed to be hedged

   65 %

Net crude oil production volume(1)

   135,719 Bbls  

Average crude oil price(2)

   $67.09 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)

   $200 – $362 per well per month  

Estimated EBITDA (in thousands):

  

Gas and oil production segment margin

   $  69,373  

Partnership management segment margin

   49,327  
      

Total segment margin(4)

   $118,700  

General and administrative expense(5)

   (24,549 )

Other

   754  
      

Estimated EBITDA

   $  94,905  
      

 

  (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 September 30, 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 798 additional gas and oil wells we project to be connected during the twelve months ending September 30, 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 June 30, 2006

   22,596    419    25,110

Twelve months ending September 30, 2007

   25,558    372    27,790

 

  (2)   Our weighted average net natural gas sales price of $8.81 per Mcf is calculated by taking into account the fact that we have hedged 6,039,572 Mcf (or approximately 65% of our forecasted gas production volume for the twelve months ended September 30, 2007) at a weighted average natural gas sales price of approximately $9.16 per Mcf, and have unhedged production volumes (3,289,280 Mcf) at an assumed price of $8.17 per Mcf, which is based on the twelve month NYMEX strip at September 15, 2006 for the twelve months ending September 30, 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 $0.71. 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 September 30, 2007

   $ 8.81    $ 8.17    $ 67.09

 

  (3)   We have assumed that we will raise approximately $270.0 million through investment partnerships in the twelve-month period ending September 30, 2007 and that our equity interest in such partnerships will be approximately 35%. We have assumed that we will drill 869 gross (803 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 6,200 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 $200 to $362 per well. We expect that our well services profit margin will be approximately 40%.

 

  (4)   We have assumed total segment margin of $118.7 million for the twelve months ending September 30, 2007, as compared to pro forma total segment margin of $111.0 million for the twelve months ended June 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 $24.5 million for the twelve months ending September 30, 2007, as compared to $20.8 million of pro forma general and administrative expense for the twelve months ended June 30, 2006. The increase in our estimated general and administrative expense is attributable to salaries and benefits for current and projected employees in order to service our growth. 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 $1.8 million attributable to estimated average borrowings of $25.9 million under our proposed credit facility for the twelve month period ending September 30, 2007 at an estimated interest rate of 7.3% to fund a portion of the $47.9 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 September 30, 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 September 30, 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
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expenditures. In years when 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 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 869 gross (281 net to our interest in the partnerships) wells during the twelve months ending September 30, 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 $82.9 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 September 30, 2007 of approximately $47.9 million are expected to be incurred to drill 503 gross (158 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 September 30, 2007 to offset the expected production decline rate from our existing producing wells. We expect to fund investment capital expenditures as described in (f) below.

 

(e)   Reflects funding of the $47.9 million of estimated investment capital expenditures for the twelve months ending September 30, 2007 with $25.9 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 September 30, 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)   We will retain $5.5 million of the net proceeds from this offering within working capital for the purposes of providing cash available for coverage of the IQD amounts and thus has been included within the estimated cash available to pay distributions. While the $5.5 million will be available to pay distributions, we do not currently expect to use such cash to pay distributions for the forecast period.

 

(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 September 30, 2007.

 

      Number of
units
   Estimated
distribution
per unit
   Estimated
annual
distributions

Common units

   35,275,000    $ 1.60    $ 56,440,000

Class A units

   719,898      1.60    $ 1,151,837
              

Total

   35,994,898       $ 57,591,837
              

 

(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 fiscal year ended September 30, 2005 and the twelve months ended June 30, 2006 and believe we will be in compliance with the funded debt and interest coverage covenants for the twelve months ended September 30, 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

 


 

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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.

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 September 30, 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 September 30, 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 9,328,852 Mcf during the twelve months ending September 30, 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 9,795,294 Mcf or 8,862,409 Mcf), we estimate that our estimated cash available to pay distributions would change by approximately $3.8 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 $8.81 per Mcf. If

 


 

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the average realized natural gas sales price for our net production volumes that are unhedged were to change by $1.00 per Mcf, we estimate that our estimated cash available to pay distributions would change by approximately $3.3 million, assuming no changes in any other variables, and assuming we have hedged approximately 65% 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 September 30, 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 $2.4 million.

UNAUDITED PRO FORMA AVAILABLE CASH FOR DISTRIBUTION

If we had completed the transactions contemplated in this prospectus on October 1, 2004, our pro forma available cash for distribution would have been $12.5 million for the fiscal year ended September 30, 2005. This amount would have been insufficient by approximately $45.1 million to pay the IQD rate of $0.40 per unit ($1.60 on an annualized basis) on our outstanding common units and Class A units.

If we had completed the transactions contemplated in this prospectus on July 1, 2005, our pro forma available cash for distribution would have been $17.7 million for the twelve months ended June 30, 2006. This amount would have been insufficient by approximately $39.9 million to pay the IQD rate of $0.40 per unit ($1.60 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 fiscal 2005 and the twelve months ended June 30, 2006, cash available to pay distributions, assuming, in each case, that this offering and the related transactions had been consummated at the beginning of the period.

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
September 30, 2005
       Twelve
months ended
June 30, 2006
 
     (in thousands, except per unit data and ratios)  

Pro forma net income before taxes(a)

   $ 57,543        $ 70,646  

Plus:

       

Interest expense

     735          740  

Depreciation, depletion and amortization

     14,061          19,402  
                   

EBITDA(b)

     72,339          90,788  

Less:

       

Pro forma cash interest expense(c)

     (235 )        (240 )

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

     (500 )        (500 )

Capital expenditures(e)

     (59,124 )        (72,363 )
                   

Pro forma available cash

   $ 12,480        $ 17,685  
                   

Cash distributions:(f)

       

Expected distribution per unit

   $ 1.60        $ 1.60  
                   

Distributions to our common unitholders

   $ 56,440        $ 56,440  

Distributions to our Class A unitholder

     1,152          1,152  
                   

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

   $ 57,592        $ 57,592  
                   

Shortfall

   $ (45,112 )      $ (39,907 )
                   

Debt covenant ratios

       

Funded debt/EBITDA(g)

     0.1x          0.1x  

Interest coverage ratio(g)

     305.7x          376.2x  

Current ratio(g)

     1.4x          1.4x  

(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)   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 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.
(c)   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 for the fiscal year ended September 30, 2005 and the twelve months ended June 30, 2006.
(d)   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.

 


 

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Cash distribution policy and restrictions on distributions


 

(e)   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 September 30, 2005, we drilled and completed a total of 662 gross (306 net) wells. During the twelve months ended June 30, 2006, we drilled and completed 694 gross (230 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.
(f)   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 September 30, 2007:

 

      Number of
units
   Estimated
distribution
per unit
   Estimated
annual
distributions

Common units

   35,275,000    $ 1.60    $ 56,440,000

Class A units

   719,898      1.60      1,151,837
              

Total

   35,994,898       $ 57,591,837
              

 

(g)   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 fiscal year ended September 30, 2005 and the twelve months ended June 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 for the years ended September 30, 2003, 2004 and 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 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 nine months ended June 30, 2005 and 2006 and the balance sheet information as of June 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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Selected historical financial data


 

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

Income statement data:

             

Revenues:

             

Gas and oil production

  $ 36,681     $ 28,916     $ 38,639     $ 48,526     $ 63,499     $ 44,669     $ 68,894  

Partnership management:

             

Well construction and completion

    43,464       55,736       52,879       86,880       134,338       98,758       126,833  

Administration and oversight

    3,632       4,805       5,090       9,874       13,223       7,315       8,098  

Well services

    7,403       7,585       7,635       8,430       9,552       7,020       8,713  

Gathering(1)

    3,448       3,497       3,898       4,191       4,359       3,186       5,981  
                                                       

Total revenues

    94,628       100,539       108,141       157,901       224,971       160,948       218,519  

Expenses:

             

Gas and oil production and exploration(1)

    7,832       8,264       8,486       8,838       9,070       6,667       10,118  

Partnership management:

             

Well construction and completion

    36,602       48,443       45,982       75,548       116,816       85,876       110,288  

Well services

    2,960       3,747       3,773       4,398       5,167       3,800       5,275  

Gathering(1)

    103       48       29       53       52       37       176  

Gathering fee – Atlas Pipeline(1)

    13,140       10,756       14,564       17,189       21,929       15,672       23,675  

General and administrative

    10,912       9,045       8,390       11,637       15,930       7,525       14,592  

Compensation reimbursement – affiliate

    1,150       1,181       1,400       1,050       602       602       859  

Depreciation, depletion and amortization

    9,594       9,409       9,938       12,064       14,061       9,762       15,103  
                                                       

Total operating expenses

    82,293       90,893       92,562       130,777       183,627       129,941       180,086  
                                                       

Operating income

    12,335       9,646       15,579       27,124       41,344       31,007       38,433  

Other income (expenses):

             

Interest income

    791       686       251       250       317       220       160  

Other – net

    406       865       107       194       (238 )     (129 )     254  
                                                       

Total other income (expenses)

    1,197       1,551       358       444       79       91       414  
                                                       

Net income before taxes

  $ 13,532     $ 11,197     $ 15,937     $ 27,568     $ 41,423     $ 31,098     $ 38,847  
                                                       

Cash flow data:

             

Cash provided by operating activities

  $ 40,764     $ 783     $ 20,365     $ 42,523     $ 65,444     $ 48,377     $ 56,885  

Cash used in investing activities

    (24,608 )     (15,943 )     (22,112 )     (32,709 )     (59,050 )     (42,689 )     (54,691 )

Cash provided by (used in) financing activities

    (394 )     2,289       34       (14,916 )     (320 )     (325 )     86  

Capital expenditures

    19,105       16,832       22,607       33,252       59,124       42,775       54,473  

Other financial information (unaudited):

             

EBITDA

  $ 23,126     $ 20,606     $ 25,875     $ 39,632     $ 55,484     $ 40,860     $ 53,950  

Balance sheet data (at period end):

             

Total assets

  $ 173,319     $ 161,464     $ 178,451     $ 198,454     $ 270,402     $ 245,421     $ 351,568  

Liabilities associated with drilling contracts

    13,770       4,948       22,157       29,375       60,971       55,627       88,810  

Advances from affiliates

    53,938       75,602       34,776       30,008       13,897       16,163       4,994  

Long-term debt, including current maturities

    —         160       194       420       81       95       112  

Total debt

    53,938       75,762       34,970       30,428       13,978       16,258       5,106  

Combined equity

    80,228       67,398       102,031       109,461       146,142       136,113       169,238  

(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 June 30, 2006, our principal assets consisted generally of:

 

Ø   working interests in 6,252 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 92 investment partnerships and a registered broker-dealer which acts as the dealer-manager of our investment partnership offerings;

 

Ø   approximately 543,400 gross (491,000 net) acres, primarily in the Appalachian Basin, over half of which, or 286,700 gross (273,200 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 209,000 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 June 30, 2006, we produced 25,110 Mcfe/d net to our interest in the production of our investment partnerships and including our direct interests in producing wells, which 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 June 30, 2006, we had identified approximately 500 proved undeveloped drilling locations and over 2,400 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 $200 to $362, 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 June 30, 2006, we owned interests in 6,884 gross wells, principally in the Appalachian Basin, of which we operated 5,833. On average during the quarter ended June 30, 2006, gross production from our wells was 81.235 MMcfe/d, or approximately 11.8 Mcfe/d per well. Over the past three fiscal years we have drilled 1,463 gross (565 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 209,000 acres owned by Knox Energy. As of June 30, 2006, we had drilled 103 net wells under this agreement. As of June 30, 2006, we had identified approximately 500 proved undeveloped drilling locations and over 2,400 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 June 30, 2006 we had financial hedges and physical hedges in place for approximately 65% of our expected production for the twelve months ending September 30, 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 fiscal 2006. 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.

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

 


 

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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, 2005 or the nine-month period ended June 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:

 

                       Nine months ended  
     Years ended September 30,     June 30,  
      2003     2004     2005     2005     2006  

Production revenues (in thousands):

          

Gas(1)

   $ 34,276     $ 42,532     $ 55,376     $ 38,916     $ 61,781  

Oil

   $ 4,307     $ 5,947     $ 8,039     $ 5,695     $ 7,061  
Production volumes:           

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

     19,087       19,905       20,892       20,275       22,553  

Oil (Bbls/d)

     438       495       433       438       420  

Total (Mcfe/d)

     21,715       22,875       23,490       22,903       25,073  

Average sales prices:

          

Gas (per Mcf)(3)

   $ 4.92     $ 5.84     $ 7.26     $ 7.03     $ 10.03  

Oil (per Bbl)

   $ 26.91     $ 32.85     $ 50.91     $ 47.57     $ 61.53  

Production costs(4):

          

As a percent of production revenues

     13 %     11 %     10 %     10 %     8 %

Per Mcfe

   $ 0.85     $ 0.87     $ 0.95     $ 0.94     $ 1.36  

Depletion per Mcfe

   $ 1.01     $ 1.22     $ 1.42     $ 1.34     $ 2.00  

(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 (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.

 


 

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(3)   Our average sales price before the effects of financial hedging was $5.08 and $9.36 for fiscal 2003 and nine months ended June 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,   

Nine months ended

June 30,

      2003    2004    2005    2005    2006

Average construction and completion revenue per well

   $ 187    $ 193    $ 218    $ 218    $ 266

Average construction and completion cost per well

     163      168      190      190      231
                                  

Average construction and completion segment margin per well

   $ 24    $ 25    $ 28    $ 28    $ 35
                                  

Segment margin

   $ 6,897    $ 11,332    $ 17,522    $ 12,882    $ 16,545
                                  

Net wells drilled

     282      450      615      453      478
                                  

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

Gas and Oil Production

Our natural gas revenues were $61.8 million in the nine months ended June 30, 2006, an increase of $22.9 million (59%) from $38.9 million in the nine months ended June 30, 2005. The increase was attributable to an increase in the average sales price of natural gas of 43% and an increase of 11% in the volume of natural gas produced in the nine months ended June 30, 2006. The $22.9 million increase in natural gas revenues consisted of $16.6 million attributable to increases in natural gas sales prices and $6.3 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 $7.1 million in the nine months ended June 30, 2006, an increase of $1.4 million (24%) from $5.7 million in the nine months ended June 30, 2005, primarily due to an increase in the average sales price of oil of 29% for the nine months ended June 30, 2006 as compared to the prior year similar period. The $1.4 million increase consisted of $1.7 million attributable to increases in sales prices partially offset by $304,000 attributable to decreased production volumes.

Our production costs were $10.1 million in the nine months ended June 30, 2006, an increase of $3.4 million (52%) from $6.7 million in the nine months ended June 30, 2005. This increase includes an

 


 

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increase in labor and maintenance costs associated with an increase in the number of wells we own and operate from the prior year period. The decrease in production costs as a percent of production revenues in the nine months ended June 30, 2006 as compared to June 30, 2005 was due to an increase in our average sales price, which more than offset the increase in production costs per Mcfe.

Well Construction and Completion

Our well construction and completion segment margin was $16.5 million in the nine months ended June 30, 2006, an increase of $3.6 million (28%) from $12.9 million in the nine months ended June 30, 2005. During the nine months ended June 30, 2006, the increase of $3.6 million was attributable to an increase in the gross profit per well ($2.7 million) and an increase in the number of wells drilled ($865,000). 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 June 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 $75.4 million of funds raised in our investment programs that have not been applied to the completion of wells as of June 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 in the remainder of 2006. During the fiscal year ended September 30, 2006, we raised $199.8 million. We anticipate oil and gas prices will continue to favorably impact our fundraising and therefore our drilling revenues in the twelve months ending September 30, 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 $8.1 million in the nine months ended June 30, 2006, an increase of $800,000 from $7.3 million in the nine months ended June 30, 2005. This increase resulted from an increase in the number of wells drilled and managed for our investment partnerships in the nine months ended June 30, 2006 as compared to the nine months ended June 30, 2005.

Well Services

Our well services revenues were $8.7 million in the nine months ended June 30, 2006, an increase of $1.7 million (24%) from $7.0 million in the nine months ended June 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 June 30, 2006.

Our well services expenses were $5.3 million in nine months ended June 30, 2006, an increase of $1.5 million (39%) from $3.8 million in the nine months ended June 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.

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.

 


 

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Our gathering fee to Atlas Pipeline was $23.7 million for the nine months ended June 30, 2006, an increase of $8.0 million (51%) from $15.7 in the nine months ended June 30, 2005. The increase in the nine months ended June 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 $14.6 million in the nine months ended June 30, 2006, an increase of $7.1 million (95%) from $7.5 million in the nine months ended June 30, 2005. 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 nine months ended June 30, 2006 is principally attributed to the following:

 

Ø   Salaries and wages increased $4.4 million due to an increase in executive salaries and in the number of employees as a result of Atlas America’s spin off from Resource America.

 

Ø   Professional and legal fees increased $1.1 million primarily due to higher audit fees and implementation of Sarbanes-Oxley Section 404 compliance.

 

Ø   Expense recognized in connection with our non-cash stock compensation increased $1.2 million; there were no such expenses in the prior year similar period.

 

Ø   Directors’ fees increased $892,000 as a result of Atlas America’s spin-off from Resource America.

 

Ø   Net syndication costs decreased $620,000 due to the timing of expenses paid in relation to the drilling funds we raise in our public and private partnerships.

Net Expense Reimbursement—Affiliate

Our net expense reimbursement—affiliate was $859,000 in the nine months ended June 30, 2006, an increase of $257,000 (43%) from $602,000 in the nine months ended June 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.

Depletion

Our depletion of oil and gas properties as a percentage of oil and gas revenues was 20% in the nine months ended June 30, 2006, compared to 19% in the nine months ended June 30, 2005. Depletion expense per Mcfe was $2.00 in the nine months ended June 30, 2006, an increase of $0.66 (49%) per Mcfe from $1.34 in the nine months ended June 30, 2005. Increases in our depletable basis and production volumes caused depletion expense to increase to $13.7 million in the nine months ended June 30, 2006 compared to $8.4 million in the nine months ended June 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.

 


 

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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 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. We will recognize this amount as income in the year ending September 30, 2006.

Administration and Oversight

Our administration and oversight fees were $13.2 million in fiscal 2005, an increase of $3.3 million (33%) from $9.9 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.

 


 

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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 $15.9 million in fiscal 2005, an increase of $4.3 million (37%) from $11.6 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   Salaries and wages increased $2.1 million due to an increase in executive salaries and in the number of employees in anticipation of Atlas America’s spin-off from Resource America.

 

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.

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.

 


 

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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 not been appl