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

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

  in   Show  and 
  As Of               Filer                 Filing     As/For/On Docs:Pgs              Issuer               Agent

11/01/06  Atlas Energy Resources/LLC        S-1/A                 15:510                                    RR Donnelley/FA

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  2,751K 
 2: EX-1.1      Form of Underwriting Agreement                      HTML    209K 
 3: EX-8.1      Opinion of Ledgewood, P.C.                          HTML     11K 
 4: EX-10.1     Form of Contribution and Assumption Agreement       HTML     63K 
 5: EX-10.2     Form of Omnibus Agreement                           HTML     27K 
 6: EX-10.3     Form of Management Agreement                        HTML     63K 
 7: EX-10.4.(A)  Master Natural Gas Gathering Agreement             HTML     60K 
 8: EX-10.4.(B)  Natural Gas Gathering Agreement                    HTML     54K 
 9: EX-10.4.(C)  Amendment to Mater Natural Gas Gathering           HTML     17K 
                          Agreement                                              
10: EX-10.4.(D)  Form of Amendment and Joinder to Gas Gathering     HTML     25K 
                          Agreement                                              
11: EX-10.5.(A)  Ominbus Agreement, Dated February 2, 2000          HTML     39K 
12: EX-10.5.(B)  Form of Amendment and Joinder to Omnibus           HTML     23K 
                          Agreement                                              
13: EX-10.8     Form of Long-Term Incentive Plan                    HTML     39K 
14: EX-10.9     Drilling and Operating Agreement                    HTML    148K 
15: EX-23.1     Consent of Grant Thornton Llp                       HTML      7K 


S-1/A   ·   Amendment No. 2 to Form S-1 Registration Statement
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page
"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;

 

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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.

Picture -- 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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Risk factors


 

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 ca