EX-99.1 3 d812275dex991.htm EX-99.1 EX-99.1
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Exhibit 99.1

 

SUBJECT TO COMPLETION, DATED JANUARY 30, 2015

 

LOGO

, 2015

Dear Atlas Energy, L.P. Unitholder:

We are pleased to inform you that the board of directors of the general partner of Atlas Energy, L.P. has approved the distribution of approximately 52.0 million common units representing a 100% limited liability company interest in Atlas Energy Group, LLC, which we also refer to as “New Atlas,” a Delaware limited liability company and wholly owned subsidiary of Atlas Energy that will hold all of Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P. (a publicly traded master limited partnership and independent developer and producer of natural gas, crude oil and natural gas liquids), Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets.

The distribution will be made by Atlas Energy on a pro rata basis to its common unitholders, and, as a result of the distribution, New Atlas will become a separate, publicly traded company. We expect the distribution of New Atlas common units to occur on February 28, 2015 by way of a pro rata distribution to Atlas Energy unitholders. Each Atlas Energy unitholder will receive one common unit of New Atlas for each Atlas Energy common unit held by such unitholder at the close of business on February 25, 2015, the record date of the distribution. Atlas Energy will not distribute any fractional common units of New Atlas, but instead will distribute cash in lieu of any fractional common unit of New Atlas that you would have received after application of the above ratio. Following the distribution, Atlas Energy will no longer own any common units of New Atlas and, as more fully described in the accompanying information statement, the New Atlas unitholders will elect the board of directors of New Atlas.

Immediately following the distribution, Atlas Energy will continue to hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s common units in Atlas Pipeline Partners, L.P. (a publicly traded master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services), and Atlas Energy will be acquired by Targa Resources Corp. through a merger of a subsidiary of Targa Resources with and into Atlas Energy, with Atlas Energy surviving this merger as a subsidiary of Targa Resources. We refer to this merger as the “Atlas Merger.” In addition, Atlas Pipeline Partners will be acquired by Targa Resources Partners LP through a merger of a subsidiary of Targa Resources Partners with and into Atlas Pipeline Partners, with Atlas Pipeline Partners surviving this merger as a subsidiary of Targa Resources Partners. We refer to this merger as the “APL Merger.” The distribution, the Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur.

The New Atlas common units issued in the distribution will be in book-entry form only, which means that no physical stock certificates will be issued. If you own your Atlas Energy common units through a broker, your brokerage account will be credited with the new common units of New Atlas. If you have an account with Atlas Energy’s transfer agent, the new common units of New Atlas will be credited to that account. Unitholder approval of the distribution is not required, and you are not required to take any action to receive your common units of New Atlas. Following the distribution, if you are an Atlas Energy unitholder on the record date, you will receive common units of New Atlas, in addition to the merger consideration of 0.1809 of a share of Targa Resources Corp. common stock, par value $0.001 per share, and $9.12 in cash, without interest, that you will receive as a result of the Atlas Merger. Your New Atlas units will not be affected by the Atlas Merger.

In general, the distribution of common units of New Atlas by Atlas Energy should not be taxable for U.S. federal income tax purposes, except to the extent that the aggregate amount of money you receive (including cash received in lieu of fractional units), or are deemed to receive, as a result of the distribution, exceeds the tax basis in your interest in Atlas Energy common units immediately before the distribution. The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution later in this information statement and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

New Atlas has applied to have its common units listed on the New York Stock Exchange under the symbol “ATLS.” Following the Atlas Merger, Atlas Energy will be delisted from and will cease to trade on the New York Stock Exchange.

We have prepared an information statement, which describes the distribution of common units of New Atlas in detail and contains important information about New Atlas. We are mailing to all Atlas Energy common unitholders a notice with instructions on how to access the information statement online and receive hard copies. No action is required by you, but we urge you to read this information statement carefully. For additional information about the mergers of Atlas Energy and Targa Resources and of Atlas Pipeline Partners and Targa Resources Partners, we encourage you to read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

We want to thank you for your continued support of Atlas Energy, and we look forward to your support of New Atlas in the future.

 

Edward E. Cohen

Chief Executive Officer

Atlas Energy GP, LLC

Jonathan Z. Cohen

Executive Chairman of the Board of Directors

Atlas Energy GP, LLC


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Exhibit 99.1

 

Information contained herein is subject to completion or amendment. A Registration Statement on Form 10 relating to these securities has been filed with the U.S. Securities and Exchange Commission under the U.S. Securities Exchange Act of 1934, as amended.

 

PRELIMINARY AND SUBJECT TO COMPLETION, DATED JANUARY 30, 2015

INFORMATION STATEMENT

ATLAS ENERGY GROUP, LLC

 

 

This information statement is being furnished in connection with the distribution by Atlas Energy, L.P. to its unitholders of approximately 52.0 million common units representing a 100% limited liability company interest in Atlas Energy Group, LLC (which we refer to in this information statement as “New Atlas”), which will, at the time of the distribution, hold, directly or indirectly, all of Atlas Energy’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P. (a publicly traded master limited partnership and independent developer and producer of natural gas, crude oil and natural gas liquids), Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets.

The distribution will be made by Atlas Energy on a pro rata basis to its unitholders, and, as a result of the distribution, New Atlas will become a separate, publicly traded company. For every common unit of Atlas Energy held of record by you as of the close of business on February 25, 2015, the record date for the distribution, you will receive one common unit of New Atlas. You will receive cash in lieu of any fractional common unit of New Atlas that you would have received after application of the above ratio. We expect the distribution to occur on February 28, 2015, which we refer to as the “distribution date.” Following the distribution, Atlas Energy will no longer own any common units of New Atlas and, as more fully described in the accompanying information statement, the New Atlas unitholders will elect the board of directors of New Atlas.

Immediately following the distribution, Atlas Energy, which will continue to hold the assets related to its “Atlas Pipeline Partners” segment, will be acquired by Targa Resources Corp. through a merger of a subsidiary of Targa Resources with and into Atlas Energy, with Atlas Energy surviving the merger as a subsidiary of Targa Resources. We refer to this merger as the “Atlas Merger.” In addition, Atlas Pipeline Partners will be acquired by Targa Resources Partners LP through a merger of a subsidiary of Targa Resources Partners with and into Atlas Pipeline Partners, with Atlas Pipeline Partners surviving this merger as a subsidiary of Targa Resources Partners. We refer to this merger as the “APL Merger.” The distribution, the Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. This information statement is being sent to you to describe the distribution and requires no action by you. Please refer to the proxy statement/prospectus relating to the Atlas Merger for additional information regarding that transaction and the APL Merger.

In general, the distribution of common units of New Atlas by Atlas Energy should not be taxable for U.S. federal income tax purposes, except to the extent that the aggregate amount of money you receive (including cash received in lieu of fractional units), or are deemed to receive, as a result of the distribution exceeds the tax basis in your interest in Atlas Energy common units immediately before the distribution. The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution later in this information statement and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

As discussed under “The Separation and Distribution—Trading Prior to the Distribution Date,” if you sell your Atlas Energy common units in the “regular-way” market before the distribution, you also will be selling your right to receive New Atlas common units in connection with the distribution.


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The distribution, the Atlas Merger and the APL Merger will each occur only if the other occurs or will occur. If the conditions to the Atlas Merger (including, among others, approval of the Atlas Merger by the Atlas Energy unitholders and the Targa Resources stockholders) are not satisfied or waived, the conditions to the distribution will not be satisfied, and Atlas Energy will not be required to complete the distribution. Likewise, if the conditions to the APL Merger (including, among others, approval of the APL Merger by the Atlas Pipeline Partners unitholders) are not satisfied or waived, the conditions to the distribution will not be satisfied, and Atlas Energy will not be required to complete the distribution. As a result, the record date for the distribution, the distribution date and the closing date for the Atlas Merger will be the same day.

Following the distribution, if you are an Atlas Energy unitholder on the record date, you will receive common units of New Atlas, in addition to the merger consideration of 0.1809 of a share of Targa Resources Corp. common stock, par value $0.001 per share, and $9.12 in cash, without interest, that you will receive as a result of the Atlas Merger. Your New Atlas units will not be affected by the Atlas Merger.

No vote of Atlas Energy unitholders is required in connection with the distribution. Therefore, you are not being asked for a proxy, and you are requested not to send us a proxy, in connection with the distribution. Atlas Energy is seeking approval from its unitholders for the Atlas Merger at a special meeting of Atlas Energy unitholders to be held on February 20, 2015. In connection with the special meeting, Atlas Energy has distributed a proxy statement/prospectus, which we refer to as the “Proxy Statement,” to all unitholders of its common units. The Proxy Statement contains a proxy and describes the procedures for voting shares of Atlas Energy common units and other details regarding the special meeting. As a result, the registration statement on Form 10 of which this information statement is a part does not contain a proxy and is not intended to constitute solicitation material under U.S. federal securities law.

If the conditions for consummating the distribution and the Atlas Merger (including, among others, approval of the Atlas Merger by the Atlas Energy unitholders and the Targa Resources stockholders) are satisfied or waived, no further action on your part is necessary for you to receive the common units of New Atlas. You do not need to take any action for the distribution to occur. You do not need to pay any consideration, exchange or surrender your existing common units of Atlas Energy or take any other action to receive your New Atlas common units. However, you will be required to surrender your common units of Atlas Energy in order to receive, for each common unit you own of Atlas Energy, 0.1809 of a share of Targa Resources Corp. common stock and $9.12 in cash, without interest, in connection with the Atlas Merger. That process is described in more detail in the Proxy Statement relating to the Atlas Merger.

All of the outstanding New Atlas common units are currently owned by Atlas Energy. There currently is no public trading market for such common units, although we expect that a limited market, commonly known as a “when-issued” trading market, will develop shortly before the record date for the distribution, and we expect “regular-way” trading of New Atlas common units to begin on the first trading day following the distribution date. New Atlas has applied to have its common units authorized for listing on the New York Stock Exchange under the ticker symbol “ATLS.” Following the Atlas Merger, Atlas Energy will be delisted from and will cease to trade on the NYSE.

This information statement will be made publicly available at www.materialnotice.com beginning                      , 2015, and notices of this information statement’s availability will be first sent to Atlas Energy unitholders on or about                 .

 

 

In reviewing this information statement, you should carefully consider the matters described in the section entitled “Risk Factors” beginning on page 31 of this information statement.

 

 

Neither the U.S. Securities and Exchange Commission nor any state securities commission has approved or disapproved of any of the securities of Atlas Energy Group, LLC or determined whether this information statement is truthful or complete. Any representation to the contrary is a criminal offense.

This information statement does not constitute an offer to sell or the solicitation of an offer to buy any securities.

 

 

The date of this information statement is                     , 2015.


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TABLE OF CONTENTS

 

     Page  

NOTE REGARDING THE USE OF CERTAIN TERMS

     ii   

INDUSTRY AND MARKET DATA

     ii   

QUESTIONS AND ANSWERS ABOUT THE DISTRIBUTION

     1   

INFORMATION STATEMENT SUMMARY

     10   

SUMMARY HISTORICAL AND UNAUDITED PRO FORMA COMBINED FINANCIAL INFORMATION

     26   

SUMMARY RESERVE DATA

     29   

RISK FACTORS

     31   

FORWARD-LOOKING STATEMENTS

     66   

THE SEPARATION AND DISTRIBUTION

     69   

CASH DISTRIBUTION POLICY

     76   

CAPITALIZATION

     107   

SELECTED FINANCIAL DATA

     108   

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

     113   

BUSINESS

     155   

MANAGEMENT

     186   

DIRECTORS

     189   

COMPENSATION DISCUSSION AND ANALYSIS

     198   

EXECUTIVE COMPENSATION

     210   

DESCRIPTION OF MATERIAL INDEBTEDNESS

     232   

SECURITY OWNERSHIP OF MANAGEMENT, DIRECTORS AND PRINCIPAL UNITHOLDERS

     233   

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

     234   

CONFLICTS OF INTEREST AND DUTIES

     243   

DESCRIPTION OF OUR COMMON UNITS

     247   

OUR LIMITED LIABILITY COMPANY AGREEMENT

     249   

CERTAIN U.S. FEDERAL INCOME TAX MATTERS

     260   

WHERE YOU CAN FIND MORE INFORMATION

     280   

GLOSSARY OF TERMS

     281   

INDEX TO FINANCIAL STATEMENTS

     F-1   

ANNEX A—THIRD AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF ATLAS ENERGY GROUP, LLC

     A-1   

 

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NOTE REGARDING THE USE OF CERTAIN TERMS

Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement, including the combined financial statements of New Atlas, assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution. References to New Atlas’s business assume that it contains all of Atlas Energy, L.P.’s assets and businesses, other than those related to its “Atlas Pipeline Partners” segment. Unless the context otherwise requires, references in this information statement to “Atlas Energy Group, LLC,” “Atlas Energy Group,” “New Atlas,” “we,” “us,” “our” and “our company” refer to Atlas Energy Group, LLC a Delaware limited liability company, and its combined subsidiaries and whose common units will be distributed in the distribution.

References in this information statement to “Atlas Energy” or “Atlas Energy, L.P.” refer to Atlas Energy, L.P., a Delaware limited partnership. References in this information statement to “ARP” or “Atlas Resource Partners” refer to Atlas Resource Partners, L.P., a Delaware limited partnership. References in this information statement to “APL” or “Atlas Pipeline Partners” refer to Atlas Pipeline Partners, L.P., a Delaware limited partnership and subsidiary of Atlas Energy. References in this information statement to “Atlas Pipeline Partners GP” refer to Atlas Pipeline Partners GP, LLC, a Delaware limited liability company that is the general partner of APL. References in this information statement to “AEI” refer to Atlas Energy, Inc. the former owner of Atlas Energy’s general partner. References to “Targa Resources” refer to Targa Resources Corp., a Delaware corporation, and references to “Targa Resources Partners” refer to Targa Resources Partners LP, a Delaware limited partnership and subsidiary of Targa Resources.

INDUSTRY AND MARKET DATA

In this information statement, we rely on and refer to information and statistics regarding the natural gas and oil production and development industries. We obtained this data from independent publications or other publicly available information that we believe to be reliable.

 

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QUESTIONS AND ANSWERS ABOUT THE DISTRIBUTION

 

What is New Atlas?

New Atlas is the name by which we refer to Atlas Energy Group, LLC following the separation of Atlas Energy’s midstream business from the remainder of its businesses. Following the separation, New Atlas will hold all of Atlas Energy’s businesses other than its midstream business, including holding:

 

    the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners;

 

    Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States;

 

    Atlas Energy’s general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business; and

 

    Atlas Energy’s natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

 

  Following the separation, Atlas Energy will continue to hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s common units in Atlas Pipeline Partners, L.P. (a publicly traded master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services).

 

  Atlas Energy currently owns all of the limited liability company interests of New Atlas. The board of directors of the general partner of Atlas Energy has approved the distribution to the Atlas Energy unitholders of approximately 52.0 million common units representing a 100% limited liability company interest in New Atlas. We refer to this distribution of common units as the “distribution.”

 

Why is Atlas Energy separating New Atlas’s business and distributing its common units?

Atlas Energy is undertaking the separation of New Atlas from Atlas Energy in the manner described in this information statement and the distribution of the common units of New Atlas in connection with its entry on October 13, 2014, into an Agreement and Plan of Merger (which we refer to as the “Atlas merger agreement”) with Targa Resources and a newly formed subsidiary of Targa Resources. The Atlas merger agreement provides for such newly formed subsidiary to merge with and into Atlas Energy, with Atlas Energy surviving the merger as a subsidiary of Targa Resources. We refer to this transaction as the “Atlas Merger.” Atlas Energy agreed in the Atlas merger agreement that, prior to the Atlas Merger, it will transfer its assets and liabilities other than those related to its “Atlas Pipeline Partners” segment to New Atlas and effect a pro rata distribution to the Atlas unitholders of New Atlas common units representing a 100% interest in New Atlas.

 

 

On October 13, 2014, Atlas Energy also entered into an Agreement and Plan of Merger (which we refer to as the “APL merger agreement”) with APL, Atlas Pipeline Partners GP, Targa Resources,

 

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Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners. APL and Targa Resources Partners are publicly traded subsidiaries of Atlas Energy and Targa Resources, respectively. The APL merger agreement provides for the newly formed subsidiary of Targa Resources Partners to merge with and into APL, with APL surviving the merger as a subsidiary of Targa Resources Partners. We refer to this second merger as the “APL Merger.”

 

  The distribution and the Atlas Merger are each conditioned on the other and will each occur only if the other occurs. In addition, the Atlas Merger and the APL Merger are each conditioned on each other, which means that the distribution is effectively conditioned on the APL Merger. For additional information about the mergers of Atlas Energy and Targa Resources Corp. and of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

 

Why is Atlas Energy Group furnishing this document?

Atlas Energy is making this document publicly available to provide information to holders of common units of Atlas Energy as of the close of business on February 25, 2015, the record date for the distribution. Each record holder as of the record date is entitled to receive one common unit of New Atlas for each common unit of Atlas Energy held at the close of business on the record date. This document will help you understand how the separation and distribution will affect your investment in Atlas Energy and your investment in New Atlas after the separation and distribution.

 

How will the separation of New Atlas occur?

The separation will be accomplished through a transaction in which Atlas Energy will transfer to New Atlas all of its businesses to the extent they are not related to its “Atlas Pipeline Partners” segment. Following such transfer, which we refer to as the “separation,” New Atlas will own, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P., Atlas Energy’s general partner and limited partner interests in Atlas Energy’s exploration and production development subsidiary and, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets. After the separation, Atlas Energy will distribute to its unitholders, on a pro rata basis, approximately 52.0 million common units representing a 100% limited liability company interest in New Atlas.

 

What is the record date for the distribution?

We expect the record date for the distribution to be the close of business on February 25, 2015.

 

When will the distribution occur?

We expect that the distribution date will be the same date as the closing date for the Atlas Merger, which we expect to be February 28, 2015. The distribution will be made to holders of record of Atlas Energy common units as of the record date.

 

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What do unitholders need to do to participate in the distribution?

Holders of Atlas Energy common units as of the record date will not be required to take any action to receive New Atlas common units in the distribution, but you are urged to read this entire information statement carefully. No unitholder approval of the distribution is required or sought. You are not being asked for a proxy, and you are requested not to send us a proxy. You will not be required to make any payment, surrender or exchange of your Atlas Energy common units or to take any other action to receive your New Atlas common units. The distribution will not affect the number of outstanding Atlas Energy common units or any rights of Atlas Energy common units.

 

How will common units of New Atlas be issued?

You will receive New Atlas common units through the same channels that you currently use to hold or trade Atlas Energy common units. If you own Atlas Energy common units as of the close of business on the record date, Atlas Energy, with the assistance of Broadridge Corporate Issuer Solutions, Inc., or Broadridge, the distribution agent, will electronically issue New Atlas common units to you or to your brokerage firm on your behalf by way of direct registration in book-entry form. New Atlas will not issue paper certificates. If you are a registered unitholder of Atlas Energy (meaning you own your units directly through an account with Atlas Energy’s transfer agent), Broadridge will mail you a book-entry account statement that reflects the number of New Atlas common units you own. If you own your Atlas Energy common units through a bank or brokerage account, your bank or brokerage firm will credit your account with the New Atlas common units.

 

  Following the distribution, unitholders whose common units are held at the transfer agent may request that their common units of New Atlas be transferred to a brokerage or other account at any time. You should consult your broker if you wish to transfer your units.

 

How many common units of New Atlas will I receive in the distribution?

Atlas Energy will distribute to you one common unit of New Atlas for each common unit of Atlas Energy held at the close of business on the record date. Based on approximately 52.0 million common units of Atlas Energy that are expected to be outstanding as of the record date, a total of approximately 52.0 million common units of New Atlas will be distributed. For additional information on the distribution, see “The Separation and Distribution” beginning on page 69.

 

Will New Atlas issue fractional units in the distribution?

No. New Atlas will not issue fractional common units in the distribution. Fractional units that Atlas Energy unitholders otherwise would have been entitled to receive will instead be aggregated and sold in the public market by the distribution agent. The aggregate net cash proceeds of these sales will be distributed ratably to those unitholders who would otherwise have been entitled to receive fractional units. Recipients of cash in lieu of fractional units will not be entitled to any interest on the amounts of payment made in lieu of fractional units.

 

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What are the conditions to the distribution?

The distribution is subject to the satisfaction (or waiver by the general partner of Atlas Energy, subject to the restrictions set forth below) of the following conditions:

 

    the U.S. Securities and Exchange Commission (the “SEC”) shall have declared effective our registration statement on Form 10, of which this information statement is a part, and no stop order relating to the registration statement is in effect;

 

    the transfer of assets and liabilities from Atlas Energy to New Atlas shall have been completed in accordance with the separation and distribution agreement;

 

    any required actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

 

    the transaction agreements relating to the separation shall have been duly executed and delivered by the parties thereto;

 

    no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the separation, distribution or any of the transactions contemplated by the separation and distribution agreement or any ancillary agreement, shall be in effect;

 

    our common units to be distributed shall have been accepted for listing on the NYSE, subject to official notice of issuance;

 

    Atlas Energy shall retain at least $5,000,000 of cash, and its net working capital (including retained cash) as of the distribution shall be no less than $5,000,000;

 

    Atlas Energy shall have received, or shall receive simultaneously with the distribution, certain payments from Targa Resources under the Atlas merger agreement and the proceeds from the cash transfers from New Atlas, as described in “Certain Relationships and Related Person Transactions—Separation and Distribution Agreement—Cash Transfers”; and

 

    the conditions required for consummating the Atlas Merger, as set forth in the Proxy Statement relating to that transaction, shall have been satisfied or waived (other than the condition that the distribution shall have occurred).

Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent. Atlas Energy and New Atlas cannot assure you that any or all of these conditions will be met. In addition, if the Atlas merger agreement is terminated before the distribution, the separation

 

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agreement will be automatically terminated and Atlas Energy will not be required to go forward with the separation. For a complete discussion of all of the conditions to the distribution, see “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

 

  Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For additional information about the merger of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

 

What do I have to do to participate in the Distribution?

Pursuant to the terms of the separation and distribution agreement, the distribution is conditioned on the satisfaction or waiver of the conditions to consummating the Atlas Merger. Pursuant to the terms of the Atlas merger agreement, the approval by a majority of the outstanding Atlas Energy unitholders of the Atlas merger agreement and the Atlas Merger, and the approval of Targa Resources’ issuance of shares in the Atlas Merger by a majority of the holders of Targa Resources common stock voting at a special meeting to approve such issuance are conditions to the Atlas Merger. Unless waived by the general partner of Atlas Energy (subject to the restrictions described above), these approvals are therefore conditions to the distribution. Atlas Energy is seeking approval from the holders of Atlas Energy common units at a special meeting of Atlas Energy’s unitholders to be held on February 20, 2015. In connection with the special meeting, Atlas Energy has distributed a proxy statement/prospectus (also referred to as the “Proxy Statement”) to all record holders of its common units. The Proxy Statement contains a proxy and describes the procedures for voting your Atlas Energy common units and other details regarding the special meeting.

 

  Holders of Atlas Energy common units as of February 25, 2015, the record date, will not need to pay any cash or deliver any other consideration, including any of their Atlas Energy common units, in order to receive units of New Atlas in the distribution.

 

What if I want to sell my common units of Atlas Energy or New Atlas?

You should consult with your financial advisors, such as your stockbroker, bank or tax advisor. Neither Atlas Energy nor New Atlas makes any recommendations on the purchase, retention or sale of common units of Atlas Energy or New Atlas.

 

  If you sell your Atlas Energy common units prior to the record date or sell your entitlement to receive common units of New Atlas in the distribution on or prior to the distribution date, you will not be entitled to receive any New Atlas common units in the distribution.

 

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What is “regular-way” and “ex-distribution” trading?

Beginning shortly before the record date, it is expected that there will be two markets in Atlas Energy, L.P. common units: a “regular-way” market and an “ex-distribution” market. Common units of Atlas Energy that trade in the “regular-way” market will trade with an entitlement to common units of New Atlas distributed pursuant to the distribution. Common units of Atlas Energy that trade in the “ex-distribution” market will trade without an entitlement to common units of New Atlas distributed pursuant to the distribution.

 

  If you decide to sell any common units of Atlas Energy before the distribution date, you should make sure your stockbroker, bank or other nominee understands whether you want to sell your common units of Atlas Energy with or without your entitlement to New Atlas common units pursuant to the distribution.

 

Where will I be able to trade common units of New Atlas?

There is not currently a public market for the common units of New Atlas. New Atlas has applied to list its common units on the New York Stock Exchange, or the NYSE, under the symbol “ATLS.” If it receives authorization for the listing, we anticipate that trading in common units of New Atlas will begin on a “when-issued” basis on or shortly before the record date and that “regular-way” trading in such common units will begin on the first trading day following the distribution date. If trading begins on a “when-issued” basis, you may purchase or sell common units of New Atlas up to and through the distribution date, but your transaction will not settle until after the distribution date. We cannot predict the trading prices for our common units before, on or after the distribution date. For more information regarding “regular-way” trading and “when-issued” trading, see the section entitled “The Separation and Distribution—Trading Prior to the Distribution Date” on page 74.

 

Will the number of common units of Atlas Energy that I own change as a result of the distribution?

No. The number of common units of Atlas Energy that you own will not change as a result of the distribution. However, as a result of the Atlas Merger, which will occur immediately following the distribution, each common unit you own of Atlas Energy will be converted into the right to receive 0.1809 of a share of TRGP common stock and $9.12 of cash, without interest. Following the Atlas Merger, Targa Resources will own all common units of Atlas Energy. Atlas Energy unitholders will own approximately 18% of the combined company on a fully diluted basis, and existing Targa Resources stockholders will own the remaining approximately 82% of the combined company on a fully diluted basis.

 

What will happen to the listing of Atlas Energy common units?

After the Atlas Merger, Atlas Energy common units will be delisted and will cease to be traded on the NYSE.

 

What are the material U.S. federal income tax consequences of the distribution of our common units by Atlas Energy?

In general, the distribution of common units of New Atlas by Atlas Energy to a U.S. holder (as defined in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260) of common units of Atlas Energy should not be taxable to the U.S. holder for U.S. federal income tax purposes, except to the extent that the aggregate amount of money such holder receives (including cash received in lieu of fractional units), or is deemed to receive, as a result

 

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of the distribution, exceeds the tax basis in such holder’s interest in Atlas Energy common units immediately before the distribution.

 

  The rules governing the tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and to consult your own tax advisor regarding the tax consequences of the distribution to you in your particular circumstances.

 

How will I determine the initial basis that I will have in the New Atlas common units I receive in the distribution?

A U.S. holder’s initial basis in the common units of New Atlas received by such U.S. holder in the distribution generally will be equal to Atlas Energy’s adjusted basis in such common units immediately before the distribution for U.S. federal income tax purposes. However, such U.S. holder’s initial basis in such common units shall not exceed the adjusted basis of such U.S. holder’s interest in Atlas Energy, reduced by any money distributed in the same transaction. Atlas Energy expects to provide unitholders with information regarding its adjusted basis for U.S. federal income tax purposes of our common units distributed in the distribution.

 

  The rules governing the determination of a unitholder’s initial basis of New Atlas common units distributed in the distribution and the other tax consequences of the distribution are complex. You are urged to read the summary of the U.S. federal income tax consequences of the distribution in the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and to consult your own tax advisor regarding the determination of your initial basis in our common units distributed to you in the distribution and the other tax consequences of the distribution to you in your particular circumstances.

 

Does New Atlas plan to pay distributions?

The determination of the amount of future cash distributions declared, if any, is at the sole discretion of New Atlas’s board of directors and will depend on various factors affecting New Atlas’s financial conditions and other matters the board of directors deems relevant.

 

  New Atlas expects to adopt a cash distribution policy under which New Atlas will distribute to its common unitholders, within 50 days after the end of each quarter, all of its “available cash” for that quarter, which generally means all cash on hand of the company at the end of the quarter less reserves that its board of directors determines are appropriate to provide for the proper conduct of the partnership’s business, to comply with applicable law or any of New Atlas’s debt instruments and to provide funds for distributions to the holders of its limited liability company interests for any one or more of the next four quarters.

 

  All decisions regarding the payment of distributions by New Atlas will be made by its board of directors from time to time in accordance with New Atlas’s limited liability company agreement.

 

 

New Atlas believes, based on the assumptions and considerations discussed in the section entitled “Cash Distribution Policy—

 

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Estimated Initial Cash Available for Distribution” beginning on page 79, that upon completion of the distribution, New Atlas’s initial quarterly distribution will, subject to proration as described below, be equal to $0.275 per common unit, or $1.10 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $14.4 million per quarter, or approximately $57.8 million per year. New Atlas’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77. We cannot assure you that any distributions will be declared or paid by us, and there is no guarantee of distributions at a particular level or of any distributions being made. We did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the twelve months ending December 31, 2015. For more information, see the section entitled “Cash Distribution Policy” beginning on page 76.

 

  We expect to pay a prorated cash distribution for the first quarter that we are a publicly traded company. This prorated cash distribution will be paid for the period beginning on the distribution date for the New Atlas common units and ending on the last day of that fiscal quarter. Any cash distributions received by New Atlas from Atlas Resource Partners between the date of the most recent cash distribution to the Atlas Energy unitholders prior to the distribution date for the New Atlas common units and such distribution date will be included in New Atlas’s first cash distribution.

 

What will the relationship be between Atlas Energy and New Atlas following the separation?

New Atlas will enter into a separation and distribution agreement with Atlas Energy to effect the separation and distribution and provide a framework for New Atlas’s relationship with Atlas Energy after the separation and will also enter into an employee matters agreement and an operating agreement for certain Atlas Energy assets in Tennessee. These agreements will provide for the allocation between Atlas Energy and New Atlas of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after New Atlas’s separation from Atlas Energy and will govern the relationship between New Atlas and Atlas Energy subsequent to the completion of the separation. Following the Atlas Merger, Atlas Energy will be a wholly owned subsidiary of Targa Resources.

 

  For more information, see the sections entitled “Risk Factors—Risks Relating to the Separation” beginning on page 52 and “Certain Relationships and Related Party Transactions” beginning on page 234.

 

Who will manage New Atlas after the separation?

New Atlas’s management team has extensive experience and background in natural gas and oil master limited partnerships and natural gas and oil development. Atlas Energy, together with its predecessors and affiliates, has been involved in the energy industry since 1968. The Atlas Energy

 

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senior personnel currently responsible for managing our assets and capital raising will continue to do so and will become our management team upon completion of the separation and distribution. For more information, see the section entitled “Management.”

 

What are the estimated costs and expenses that New Atlas expects to incur in the separation and distribution?

New Atlas expects to incur one-time expenditures of between approximately $1.0 million and $1.5 million, in addition to advisory fees, in connection with the separation and distribution. Such one-time expenditures include, among others, costs for branding the new company, NYSE listing fees, investor and other stakeholder communications, printing costs and fees of the distribution agent.

 

Are there risks to owning New Atlas common units?

Yes. New Atlas’s business is subject to both general and specific risks relating to its business, the separation and its being a separate publicly traded company. These risks are described in the section entitled “Risk Factors” beginning on page 31. We encourage you to read that section carefully.

 

Who will be the distribution agent, transfer agent and registrar for the New Atlas common units?

The distribution agent, transfer agent, and registrar for the Atlas Energy common units will be Broadridge Corporate Issuer Solutions, Inc. For questions relating to the transfer or mechanics of the distribution, you should contact:

Broadridge Corporate Issuer Solutions, Inc.

Attention: Atlas Energy, L.P. Representative

P.O. Box 1342

Brentwood, NY 11717

 

Where can I get more information about Atlas Energy and New Atlas?

Before the separation, if you have any questions relating to the separation, you should contact:

Atlas Energy, L.P.

Investor Relations

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, Pennsylvania 15275

(877) 280-2857

 

  After the separation, if you have any questions relating to New Atlas common units or the distribution of our common units, you should contact:

Atlas Energy Group, LLC

Investor Relations

Park Place Corporate Center One

1000 Commerce Drive, 4th Floor

Pittsburgh, Pennsylvania 15275

(877) 280-2857

 

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INFORMATION STATEMENT SUMMARY

This summary highlights selected information from this information statement relating to New Atlas, New Atlas’s separation from Atlas Energy and the distribution of New Atlas’s common units by Atlas Energy to its unitholders. For a more complete understanding of our businesses and the separation and distribution, you should read this information statement carefully. Except as otherwise indicated or unless the context otherwise requires, the information included in this information statement, including the financial statements of New Atlas, assumes the completion of all the transactions referred to in this information statement in connection with the separation and distribution.

The information about us and our business contained in this information statement assumes that the distribution and Atlas Merger have been completed. If the conditions for consummating the distribution and the Atlas Merger (including, among others, approval of the Atlas Merger Agreement and the Atlas Merger by the Atlas Energy unitholders and approval of the issuance of Targa Resources common stock in the Atlas Merger by the Targa Resources stockholders) are not satisfied or waived, the distribution will not occur.

Our Business

We are a Delaware limited liability company formed in October 2011 by Atlas Energy to serve as the general partner of Atlas Resource Partners, L.P., which we describe below. Following the separation, we will hold all of Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment, including holding the following:

 

    the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P. (NYSE: ARP), a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and natural gas liquids, which we refer to as “NGLs,” with operations in basins across the United States. ARP sponsors and manages tax-advantaged investment partnerships, in which it coinvests, to finance a portion of its natural gas and oil production activities. At January 1, 2015, we owned 100% of the general partner Class A units and all of the incentive distribution rights in ARP, and Atlas Energy owned an approximate 27.7% limited partner interest (consisting of 20,962,485 common and 3,749,986 preferred limited partner units) in ARP;

 

    Atlas Energy’s general partner and limited partner interests in its development subsidiary (referred to as the “Development Subsidiary”), a partnership that currently conducts natural gas and oil operations in the mid-continent region of the United States. At January 1, 2015, Atlas Energy owned a 1.7% limited partner interest in the Development Subsidiary and 80.0% of its outstanding general partner Class A units, which are entitled to receive 2.0% of the cash distributed without any obligation to make further capital contributions;

 

    Atlas Energy’s interests in Lightfoot Capital Partners, L.P. and Lightfoot Capital Partners GP, LLC, its general partner, entities which we refer to collectively as “Lightfoot” or “Lightfoot Capital Partners,” and which incubate new master limited partnerships, or “MLPs,” and invest in existing MLPs. At January 1, 2015, Atlas Energy had an approximate 15.9% general partner interest and 12.0% limited partner interest in Lightfoot; and

 

    direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our direct natural gas production business as well as the distributions paid to us by the MLPs in which we own interests. Atlas Energy, together with its predecessors and affiliates, has been involved in the energy industry since 1968. The Atlas Energy personnel currently responsible for managing our assets and capital raising will continue to do so and will become our employees upon completion of the separation and distribution.

 

 

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Overview of ARP

ARP is a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs, with operations in basins across the United States. ARP is a leading sponsor and manager of tax-advantaged investment partnerships, or “Drilling Partnerships,” in which ARP co-invests, to finance a portion of its natural gas, crude oil and NGL production activities. We are the general partner of ARP and manage its businesses. As of January 1, 2015, we own 100% of ARP’s general partner Class A units, all of ARP’s incentive distribution rights and approximately 27.7% of ARP’s outstanding limited partner interest.

In February 2012, the board of directors of Atlas Energy’s general partner approved the formation of ARP as a newly created exploration and production master limited partnership and the related transfer of substantially all of Atlas Energy’s natural gas and oil development and production assets at that time and the partnership management business to ARP on March 5, 2012.

ARP’s primary business objective is to generate growing yet stable cash flows through the development and acquisition of mature, long-lived natural gas, oil and NGL properties. As of December 31, 2013, ARP’s estimated proved reserves were 1.2 Tcfe, including the reserves net to its equity interest in Drilling Partnerships. Of ARP’s estimated proved reserves, approximately 68% were proved developed and approximately 83% were natural gas. For the year ended December 31, 2013, ARP’s average daily net production was approximately 187.7 MMcfe.

Overview of Development Subsidiary

During the year ended December 31, 2013, Atlas Energy formed a new partnership subsidiary to conduct natural gas and oil operations, initially in the mid-continent region of the United States. Since its formation, the Development Subsidiary has conducted operations in the Marble Falls formation in the Fort Worth Basin, where it has drilled 13 wells, and in the Mississippi Lime area of the Anadarko Basin in Oklahoma, where it has participated in two non-operated wells. At December 1, 2014, the Development Subsidiary had capital contributions of $120.6 million, including $2.0 million from Atlas Energy to acquire its limited partner interest. Our Development Subsidiary also entered into a purchase and sale agreement to acquire interests in oil and gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas, which closed on November 5, 2014. As of January 1, 2015, we own an approximate 80.0% interest in the Development Subsidiary’s general partner and a 1.7% limited partner interest in the Development Subsidiary.

Overview of Lightfoot

Lightfoot is a private investment vehicle that focuses on investing directly in master limited partnership-qualifying businesses and assets. Lightfoot investors include affiliates of, and funds under management by, GE EFS, Atlas Energy, L.P., BlackRock Investment Management, LLC, Magnetar Financial LLC, CorEnergy Infrastructure Trust, Inc. and Triangle Peak Partners Private Equity, LP. As of January 1, 2015, we own an approximate 15.9% interest in Lightfoot’s general partner and a 12.0% interest in Lightfoot’s limited partner.

Lightfoot’s stated strategy is to make investments by partnering with, promoting and supporting strong management teams to build growth-oriented businesses or industry verticals. Lightfoot provides extensive financial and industry relationships and significant master limited partnership experience, which assist in growth via acquisitions and development projects by identifying:

 

    efficient operating platforms with deep industry relationships;

 

    significant expansion opportunities through add-on acquisitions and development projects;

 

    stable cash flows with fee-based income streams, limited commodity exposure and long-term contracts; and

 

 

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    scalable platforms and opportunities with attractive fundamentals and visible future growth.

On November 6, 2013, Arc Logistics Partners LP (“ARCX”), a master limited partnership owned and controlled by Lightfoot Capital Partners, L.P., began trading publicly on the NYSE. ARCX is focused on the terminalling, storage, throughput and transloading of crude oil and petroleum products in the East Coast, Gulf Coast and Midwest regions of the United States. ARCX’s cash flows are primarily fee-based under multi-year contracts. Lightfoot has a significant interest in ARCX through its ownership of a 40.3% limited partner interest, Lightfoot, G.P., the general partner, and all of Lightfoot’s incentive distribution rights. Lightfoot intends to utilize ARCX to facilitate future organic expansions and acquisitions for its energy logistics business.

Overview of Direct Natural Gas and Oil Production

Our consolidated gas and oil production operations consist of various shale plays in the United States, both through ARP and the Development Subsidiary and through assets that we own directly. Our direct natural gas and oil production results from certain coal-bed methane producing natural gas assets in the Arkoma Basin that Atlas Energy acquired on July 31, 2013 from EP Energy E&P Company, L.P., which we refer to as “EP Energy,” for $64.5 million, net of purchase price adjustments. We refer to this transaction as the “Arkoma Acquisition.” As a result of the Arkoma Acquisition, we have ownership interests in approximately 600 wells in the Arkoma Basin in eastern Oklahoma with average daily production of 5.1 MMcfe for the year ended December 31, 2013.

Business Strategy

Our goal is to increase the distributions to our unitholders by continuing to grow the net production from our direct natural gas and oil production business as well as the distributions paid to us by the MLPs in which we own interests. The key elements of our business strategy are to:

 

    Increase cash available for distributions to our unitholders. Our primary business objective is to increase the amount of cash distributed to us by ARP, as well as our other subsidiaries, which we can then distribute to our unitholders. We own the general partner interest and IDRs in ARP and generate substantial cash flow from the distributions we receive on these interests.

 

    Actively assist our subsidiaries in executing their business strategies. We are actively engaged in the management of ARP and our other subsidiaries and assist them in identifying, evaluating and pursuing growth strategies, acquisitions and capital-raising opportunities. Our employees manage ARP’s daily activities on behalf of ARP. In addition, Jonathan Cohen, our Executive Chairman, is chairman of the board of Lightfoot’s general partner.

 

    Expand operations through strategic acquisitions. We continually evaluate opportunities to expand our and ARP’s operations through acquisitions of developed and undeveloped properties or companies that can increase our cash available for distribution. We will continue to seek strategic opportunities in our and ARP’s current areas of operation, as well as other regions of the United States. In the first half of 2014, ARP acquired certain coal-bed methane producing natural gas assets in West Virginia and Virginia and low-decline oil and NGL assets in the Rangeley field in northwest Colorado. In September of 2014, our Development Subsidiary and ARP entered into a purchase and sale agreement to acquire interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas.

 

   

Expand our natural gas and oil production. We and ARP generate a significant portion of our respective revenue and net cash flow from natural gas and oil production. We believe ARP’s program of sponsoring investment partnerships to exploit its acreage opportunities provides it with enhanced economic returns, which we participate in through our ownership of ARP’s IDRs and general partner

 

 

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interest. We intend for ARP to continue to finance the majority of its drilling and production activities through these investment partnerships. In addition, the Development Subsidiary has completed 13 wells in the Marble Falls play and participated in two non-operated wells in the Mississippi Lime play, and we operate select assets in the Arkoma Basin.

 

    Expand ARP’s fee-based revenue through its sponsorship of Drilling Partnerships. ARP generates substantial revenue and cash flow from fees paid by the Drilling Partnerships to ARP for acting as the managing general partner. As ARP continues to sponsor Drilling Partnerships, we expect that ARP’s fee revenues from its drilling and operating agreements with its Drilling Partnerships will increase and will continue to add stability to its revenue and cash flows.

 

    Continue to maintain control of operations and costs. We believe it is important to be the operator of wells in which we, ARP or ARP’s Drilling Partnerships have an interest because we believe it will allow us and ARP to achieve operating efficiencies and control costs. As operator, we and ARP are better positioned to control the timing and plans for future enhancement and exploitation efforts, costs of enhancing, drilling, completing and producing the well, and marketing negotiations for natural gas, oil and NGL production to maximize both volumes and wellhead price. Through our management of ARP, we were the operator of the vast majority of the properties in which ARP or ARP’s Drilling Partnerships had a working interest at September 30, 2014.

 

    Continue to manage our exposure to commodity price risk. To limit our and ARP’s exposure to changing commodity prices and enhance and stabilize cash flow, we and ARP use financial hedges for a portion of our and ARP’s natural gas and oil production. We and ARP principally use fixed price swaps and collars as the mechanism for the financial hedging of commodity prices.

Competitive Strengths

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

 

    We and ARP have a high quality, long-lived reserve base. Our and ARP’s natural gas and oil properties are located principally in the Barnett Shale, the Mississippi Lime, and the Raton, Black Warrior, Fort Worth, Arkoma and Appalachian basins and the Rangely field, and are characterized by long-lived reserves, generally favorable pricing for our and ARP’s production and readily available transportation.

 

    We have significant experience in making accretive acquisitions. Our management team has extensive experience in consummating accretive acquisitions. We believe we will be able to generate acquisition opportunities of both producing and non-producing properties through our management’s extensive industry relationships. We intend to use these relationships and experience to find, evaluate and execute on acquisition opportunities.

 

    We have significant engineering, geologic and management experience. Atlas Energy’s technical team of geologists and engineers has extensive industry experience. We believe that we have been one of the most active drillers in ARP’s core operating areas and, as a result, that we have accumulated extensive geological and geographical knowledge about the area. We have also added geologists and engineers to our technical staff who have significant experience in other productive basins within the continental United States, which enables us to evaluate and, as evidenced by the EP Energy acquisition, expand our core operating areas.

 

   

ARP is one of the leading sponsors of tax-advantaged Drilling Partnerships. ARP and its predecessors have sponsored limited and general partnerships to raise funds from investors to finance development drilling activities since 1968, and we believe that ARP is one of the leading sponsors of such Drilling Partnerships in the country. We believe that ARP’s lengthy association with many of the broker-dealers

 

 

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that act as placement agents for Drilling Partnerships provide ARP with a competitive advantage over entities with similar operations. We also believe that ARP’s sponsorship of Drilling Partnerships has allowed ARP to generate attractive returns on drilling, operating and production activities.

 

    Fee-based revenues from ARP’s Drilling Partnerships and our and ARP’s substantially hedged production provide protection from commodity price volatility. ARP’s Drilling Partnerships provide ARP with stable, fee-based revenues which diminish the influence of commodity price fluctuations on cash flows. Because ARP’s Drilling Partnerships reimburse ARP on a cost-plus basis for drilling capital expenses, ARP is partially protected against increases in drilling costs. ARP’s fees for managing Drilling Partnerships accounted for approximately 16% of ARP’s segment margin for the year ended December 31, 2013. As of September 30, 2014, we and ARP had approximately 157.4 Bcfe, 4.1 Mmbbl and 0.7 Mmbbl of hedge positions, respectively, on our and ARP’s natural gas, crude oil and NGL production for 2014 through 2018.

 

    ARP’s partnership management business can improve the economic rates of return associated with natural gas and oil production activities. A well drilled, net to ARP’s equity interest, in ARP’s partnership management business will provide ARP with an enhanced rate of return. For each well drilled in a partnership, ARP receives an upfront fee on the investors’ well construction and completion costs and a fixed administration and oversight fee, which enhances ARP’s overall rate of return. ARP also receives monthly per well fees from the partnership for the life of each individual well, which also increases the rate of return.

Cash Distributions from ARP and Lightfoot

As of January 1, 2015, our equity interests in ARP and our other subsidiaries and investees consisted of:

 

    Incentive
Distribution
Rights
    General
Partner
Interest
   

Limited Partner

Interests

Our interests in ARP

    100 %(1)     100 %(2)   

20,962,485

3,749,986

562,497

 

Common Units(3)

Class C Preferred Units(4) Warrants for Class C Preferred Units(5)

Our interests in the Development Subsidiary

    —          80.0 %(6)   1.7% limited partner interest

Our interests in Lightfoot

    —          15.9 %   12.0% limited partner interest

Lightfoot’s interests in ARCX

    100 %(7)     100 %(8)   40.3% limited partner interest

 

(1)  The incentive distribution rights, or “IDRs,” entitle us to receive increasing percentages, up to a maximum of 48%, of any cash distributed by ARP as it reaches certain target distribution levels in excess of $0.46 per ARP common unit in any quarter.
(2)  Consists of 1,819,113 general partner Class A units, which are entitled to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP.
(3)  Represents an approximate 23.5% limited partner interest.
(4)  Represents an approximate 4.2% limited partner interest. The Class C preferred units pay cash distributions in an amount equal to the greater of (a) $0.51 per unit and (b) the distributions payable on each common unit at each declared quarterly distribution date. Class C preferred units are convertible, at the option of the holder, on a one-for-one basis, in whole or in part, at any time before July 31, 2016 and are mandatorily convertible on July 31, 2016.
(5)  Upon issuance of the Class C preferred units, Atlas Energy, as purchaser of the Class C preferred units, received 562,497 warrants to purchase ARP common units at an exercise price of $23.10 per unit, subject to adjustments provided therein. The warrants will expire on July 31, 2016.

 

 

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(6)  The general partner interest is entitled to receive 2% of the cash distributed by the Development Subsidiary without any obligation to make further capital contributions.
(7)  Lightfoot owns 100% of Arc Logistics GP LLC, the general partner of ARCX, which owns all of the ARCX IDRs. The ARCX IDRs entitle ARCX’s general partner to receive increasing percentages, up to a maximum of 50%, of any cash distributed by ARCX as it reaches certain target distribution levels in excess of $0.4456 per ARCX common unit in any quarter.
(8)  The general partner interest in ARCX is a non-economic interest and does not entitle its holder to receive cash distributions.

The ARP IDRs entitle us, as the indirect holder of those rights, to receive the following percentages of cash distributed by ARP as the following target cash distribution levels are reached:

 

    13.0% of all cash distributed in any quarter after each ARP common unit has received $0.46 for that quarter;

 

    23.0% of all cash distributed in any quarter after each ARP common unit has received $0.50 for that quarter; and

 

    48.0% of all cash distributed in any quarter after each ARP common unit has received $0.60 for that quarter.

In addition, our ownership of ARP’s general partner Class A units entitles us to receive 2% of the cash distributed by ARP without any obligation to make further capital contributions to ARP, and our ownership of approximately 27.7% of ARP’s limited partner ownership interest entitles us to receive distributions pro rata with ARP’s other limited partners.

The following are distributions declared and/or paid by ARP subsequent to December 31, 2013. Our board of directors adopted a monthly distribution policy for ARP effective for the month of January 2014 and later:

 

Payment

  

Record Date

  

Payment Date

   Rate  

Q4 2013

   February 10, 2014    February 14, 2014    $ 0.5800  

January 2014

   March 7, 2014    March 17, 2014      0.1933   

February 2014

   April 7, 2014    April 14, 2014      0.1933   

March 2014

   May 7, 2014    May 15, 2014      0.1933   

April 2014

   June 5, 2014    June 13, 2014      0.1933   

May 2014

   July 7, 2014    July 15, 2014      0.1933   

June 2014

   August 6, 2014    August 14, 2014      0.1966   

July 2014

   September 4, 2014    September 12, 2014      0.1966   

August 2014

   October 7, 2014    October 15, 2014      0.1966   

September 2014

   November 10, 2014    November 14, 2014      0.1966   

October 2014

   December 5, 2014    December 15, 2014      0.1966   

November 2014

   January 6, 2015    January 16, 2015      0.1966   

Following the separation, New Atlas will own 80.0% of the Development Subsidiary’s general partner, which is entitled to 2.0% of the cash distributed to the Development Subsidiary, and 15.9% of Lightfoot’s general partner, which owns ARCX’s IDRs and is entitled to distributions, up to a maximum of 50%, of any cash distributed by ARCX as it reaches certain target distribution levels in excess of $0.4456 per ARCX common unit in any quarter. New Atlas will also own 1.9% of the Development Subsidiary’s limited partner interests and 12.0% of Lightfoot’s limited partnership interests, which will be entitled to a pro rata share of distributions made by the Development Subsidiary and Lightfoot (and therefore ARCX), respectively.

 

 

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Geographic and Geologic Overview

Through December 31, 2014, we and ARP have established production positions in the following areas:

 

    the Eagle Ford Shale in southern Texas, in which our Development Subsidiary and ARP acquired acreage and producing wells in November 2014;

 

    the Barnett Shale and Marble Falls play, both in the Fort Worth Basin in northern Texas. The Barnett Shale contains mostly dry gas and the Marble Falls play, in which both ARP and our Development Subsidiary own acreage and producing wells, contains liquids rich natural gas and oil;

 

    coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming, where ARP established a position following the EP Energy Acquisition, the Arkoma Basin in eastern Oklahoma, where we established a position following the Arkoma Acquisition, as well as the Cedar Bluff area of West Virginia and Virginia, where ARP established a position following the acquisition of certain assets from GeoMet, Inc.;

 

    the Rangely field in northwest Colorado, a mature tertiary CO2 flood with low-decline oil production, where ARP acquired a 25% non-operated net working interest position in June 2014;

 

    the Appalachian Basin, including the Marcellus Shale, a rich, organic shale that generally contains dry, pipeline-quality natural gas, and the Utica Shale, which lies several thousand feet below the Marcellus Shale, is much thicker than the Marcellus Shale and trends primarily towards wet natural gas in the central region and dry gas in the eastern region;

 

    the Mississippi Lime and Hunton plays in northwestern Oklahoma, an oil and NGL-rich area; and

 

    other operating areas, including the Chattanooga Shale in northeastern Tennessee, which enables ARP to access other formations in that region such as the Monteagle and Ft. Payne Limestone, the New Albany Shale in southwestern Indiana, a biogenic shale play with a long-lived and shallow decline profile, and the Niobrara Shale in northeastern Colorado, a predominantly biogenic shale play that produces dry gas.

Gas and Oil Acquisitions

We and ARP seek to create substantial value by executing our respective strategies of acquiring properties with stable, long-life production, relatively predictable decline curves and lower risk development opportunities. Overall, we and ARP have acquired significant net proved reserves and production through the following transactions:

 

    Carrizo Barnett Shale Acquisition—On April 30, 2012, ARP acquired 277 Bcfe of proved reserves, including undeveloped drilling locations, in the core of the Barnett Shale from Carrizo Oil & Gas, Inc. for approximately $187.0 million.

 

    Titan Barnett Shale Acquisition—On July 26, 2012, ARP acquired Titan Operating, L.L.C., which owned approximately 250 Bcfe of proved reserves and associated assets in the Barnett Shale on approximately 16,000 net acres, which are 90% held by production, for approximately $208.6 million.

 

    Equal Mississippi Lime Acquisition—On April 4, 2012, ARP entered into an agreement with Equal Energy, Ltd., which we refer to as “Equal,” to acquire a 50% interest in Equal’s approximately 14,500 net undeveloped acres in the core of the oil and liquids rich Mississippi Lime play in northwestern Oklahoma for approximately $18.0 million. On September 24, 2012, ARP acquired Equal’s remaining 50% interest in approximately 8,500 net undeveloped acres included in the joint venture, additional net production in the region and substantial salt water disposal infrastructure for $41.3 million.

 

 

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    DTE Fort Worth Basin Acquisition—On December 20, 2012, ARP acquired 210 Bcfe of proved reserves in the Fort Worth Basin from DTE Energy Company for $257.4 million. The assets acquired are in close proximity to ARP’s other assets in the Barnett Shale.

 

    EP Energy Raton Basin, Black Warrior Basin and County Line Acquisition—On July 31, 2013, ARP completed the acquisition of certain assets from EP Energy for approximately $709.6 million in net cash. We refer to this transaction as the “EP Energy Acquisition.” The assets acquired included coal-bed methane producing natural gas assets in the Raton Basin in northern New Mexico, the Black Warrior Basin in central Alabama and the County Line area of Wyoming.

 

    EP Arkoma Acquisition—On July 31, 2013, Atlas Energy completed the acquisition of certain assets from EP Energy for approximately $64.5 million, net of purchase price adjustments. The assets acquired included coal-bed methane producing natural gas assets in the Arkoma Basin in eastern Oklahoma.

 

    GeoMet Acquisition—On May 12, 2014, ARP completed the acquisition of certain assets from GeoMet, Inc. for approximately $99.3 million in cash, net of purchase price adjustments, with an effective date of January 1, 2014. The assets include coal-bed methane producing natural gas assets in West Virginia and Virginia.

 

    Rangely Acquisition—On June 30, 2014, ARP completed the acquisition of a 25% non-operated net working interest in oil and NGL producing assets, representing approximately 47 Mmboe of oil equivalent reserves, for approximately $407.8 million in cash with an effective date of April 1, 2014. The assets are located in the Rangely field in northwest Colorado.

 

    Eagle Ford Acquisition—In November 2014, our Development Subsidiary and ARP acquired interests in oil and natural gas assets in the Eagle Ford Shale in South Central Atascosa County, Texas including 4,000 operated gross acres and net reserves of 12 Mmboe as of July 1, 2014. The purchase price was $339.0 million, of which $199.0 million was paid at closing and the balance will be paid during the twelve months following closing, subject to certain purchase price adjustments. The acquisition closed on November 5, 2014, with an effective date of July 1, 2014.

Commodity Risk Management

We and ARP seek to provide greater stability in our and ARP’s cash flows through the use of financial hedges for our natural gas, oil and NGLs production. The financial hedges may include purchases of regulated New York Mercantile Exchange (“NYMEX”) futures and options contracts and non-regulated over-the-counter futures and options contracts with qualified counterparties. Financial hedges are contracts between us or ARP and counterparties and do not require physical delivery of hydrocarbons. Financial hedges allow us and ARP to mitigate hydrocarbon price risk, and cash is settled to the extent there is a price difference between the hedge price and the actual NYMEX settlement price. Settlement typically occurs on a monthly basis, at the time in the future dictated within the hedge contract. Financial hedges executed in accordance with our and ARP’s secured credit facilities do not require cash margin and are secured by our and ARP’s natural gas and oil properties. To assure that the financial instruments will be used solely for hedging price risks and not for speculative purposes, we and ARP have a management committee to assure that all financial trading is done in compliance with our and ARP’s hedging policies and procedures. We and ARP do not intend to contract for positions that we and ARP cannot offset with actual production.

Risks

An investment in our common units is subject to a number of risks, including risks relating to our and ARP’s business, risks related to the separation and risks related to our common units. Set forth below are some, but not all, of these risks. Please read carefully the risks relating to these and other matters described in the sections entitled “Risk Factors” and “Forward-Looking Statements.”

 

 

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Risks Relating to Our Business

 

    Our primary assets are our partnership interests, including the IDRs, in ARP, and, therefore, our cash flow is dependent on the ability of ARP to make distributions in respect of those partnership interests.

 

    We may not have sufficient cash to pay distributions at our current quarterly distribution level or to increase distributions.

 

    The assumptions underlying the forecast of cash distributions that we include in the section entitled “Cash Distribution Policy” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash distributions to differ materially from our forecast, and we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period.

 

    Our ability to meet future financial needs may be adversely affected by our cash distribution policy.

 

    The scope and costs of the risks involved in our subsidiaries making acquisitions may prove greater than estimated at the time of the acquisition, and our subsidiaries may be unsuccessful in integrating the operations from future acquisitions and realizing the anticipated benefits of these acquisitions.

 

    Reduced incentive distributions from ARP will disproportionately affect the amount of cash distributions to which we are entitled.

 

    If in the future we cease to manage and control ARP through our ownership of its general partner interests, we may be deemed to be an investment company.

 

    Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for our and ARP’s services.

Risks Relating to Our and ARP’s Exploration and Production Business

 

    If commodity prices decline significantly, our cash flow from operations will decline.

 

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

 

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

 

    Our and ARP’s operations require substantial capital expenditures to increase our and its asset base. If we or ARP are unable to obtain needed capital or financing on satisfactory terms, we and ARP’s asset base will decline, which could cause revenues to decline and affect our and ARP’s ability to pay distributions.

 

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

 

    The physical effects of climatic change have the potential to damage facilities, disrupt operations and production activities and cause us and ARP to incur significant costs in preparing for or responding to those effects.

 

    Unless we and ARP replace our and its natural gas and oil reserves, reserves and production will decline, which would reduce cash flow from operations and income.

 

    Federal legislation and state legislative initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

 

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

 

 

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    Estimates of 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 and ARP’s reserves.

Risks Relating to ARP’s Drilling Partnerships

 

    ARP or its subsidiaries may be exposed to financial and other liabilities as the managing general partner of the Drilling Partnerships.

 

    ARP may not be able to continue to raise funds through its Drilling Partnerships at desired levels, which may restrict its ability to maintain drilling activity.

Risks Relating to the Separation

 

    We have no operating history as a separate public company, and our historical and pro forma financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results.

 

    We may not achieve some or all of the expected benefits of the separation, and the separation may adversely affect our business.

 

    After our separation from Atlas Energy, we will have debt obligations that could restrict our ability to pay cash distributions and have a negative impact on our financing options and liquidity position.

Risks Relating to Our Common Units

 

    We cannot be certain that an active trading market for our common units will develop or be sustained after the distribution and, following the distribution, our unit price may fluctuate significantly. If the unit price declines after the distribution, you could lose a significant part of your investment.

 

    There is no guarantee that our unitholders will receive quarterly distributions from us.

 

    A significant number of our common units may be traded following the distribution, which may cause our unit price to decline.

 

    Certain provisions of our limited liability company agreement, and of Delaware law, may prevent or delay an acquisition of us, which could decrease the trading price of our common units.

Tax Risks to Unitholders

 

    Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes.

 

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

 

    Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP.

 

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

 

    Unitholders may be subject to state and local taxes and return filing requirements as a result of investing in our common units.

 

    ARP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of ARP. The IRS may challenge this treatment, which could adversely affect the value of ARP’s and our common units.

 

 

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Risks Relating to Our Conflicts of Interest

 

    Although we control ARP and our Development Subsidiary through our ownership of their general partner interests, we owe duties to each such entity and its unitholders, which may conflict with our interests.

 

    Certain of our officers and directors may have actual or potential conflicts of interest because of their positions, and their duties may conflict with those of the officers and directors of ARP or our Development Subsidiary’s general partner.

 

    Our limited liability company agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to our unitholders for actions taken by our directors or officers that might otherwise constitute breaches of fiduciary duty.

 

    Our affiliates and ARP may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, and this could adversely affect our results of operations and cash available for distribution to our unitholders.

Separation and Distribution

We are a Delaware limited liability company formed in 2011 by Atlas Energy to serve as the general partner of Atlas Resource Partners, L.P. Prior to the distribution, we will hold Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment, including holding its exploration and production business. In particular, we will hold the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, Atlas Energy’s general and limited partner interests in its exploration and production Development Subsidiary, which currently conducts operations in the mid-continent region of the United States, its general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets. We do not currently conduct any significant operations outside of the operation of these assets.

In this information statement, we describe the business and assets that will be held by us following the separation and distribution. Our businesses are subject to various risks. For a description of these risks, see the sections entitled “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 31 and page 113, respectively.

The board of directors of Atlas Energy’s general partner has approved the transfer of all of Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment, to us and the distribution to the Atlas Energy unitholders of common units representing a 100% limited liability company interest in New Atlas. As a result of the separation and distribution, we will become a separate, publicly traded company. Immediately after the separation and distribution, Atlas Energy will no longer own any of our common units. As is more fully described in the accompanying information statement, our unitholders will elect the members of our board of directors.

Our Post-Separation Relationship with Atlas Energy

New Atlas will enter into a separation and distribution agreement with Atlas Energy and Atlas Energy’s general partner to effect the separation and distribution and provide a framework for New Atlas’s relationship with Atlas Energy after the separation and will also enter into an employee matters agreement and an operating agreement for certain Atlas Energy assets in Tennessee. These agreements will provide for the allocation between Atlas Energy and New Atlas of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after New Atlas’s separation from Atlas Energy and will govern the relationship between New

 

 

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Atlas and Atlas Energy subsequent to the completion of the separation. Following the Atlas Merger, Atlas Energy will be a wholly owned subsidiary of Targa Resources. For more information, see the section entitled “Risk Factors—Risks Relating to the Separation” and “Certain Relationships and Related Person Transactions.”

Reasons for the Separation and Distribution

The board of directors of Atlas Energy’s general partner believes, given the current makeup of its assets and market environment, that separating its midstream business from the remainder of its businesses, including its exploration and production business, is in the best interests of Atlas Energy and its unitholders and has concluded that the separation will provide each company with a number of opportunities and benefits, including the following:

 

    The separation will enable Atlas Energy unitholders to keep an interest in Atlas Energy’s non-midstream assets following the Atlas Merger with Targa Resources.

 

    The separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and New Atlas, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

    The separation will create an acquisition currency in the form of units that will enable New Atlas to purchase, and to assist ARP in purchasing, developed and undeveloped resources to accelerate growth of its natural gas and oil production and development business without diluting Atlas Energy unitholders’ participation in growth at Atlas Pipeline Partners, L.P., a publicly traded partnership the general partner of which is owned by Atlas Energy, or its successor. Current industry trends have created a significant opportunity for New Atlas to grow, and to assist ARP in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

    The separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

    The separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

    The separation will provide enhanced liquidity to holders of Atlas Energy common units, who will hold two separate publicly traded securities that they may seek to retain or monetize.

 

    The separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model, and financial returns.

The board of directors of Atlas Energy’s general partner also considered a number of potentially negative factors in evaluating the separation and distribution, including, among others, risks relating to the creation of a new public company, possible increased costs and one time separation costs, but concluded that the potential benefits of the separation and distribution outweighed these factors. For more information, see the sections of this information statement entitled “The Separation and Distribution—Reasons for the Separation and Distribution” and “Risk Factors.”

The distribution of our common units as described in this information statement is subject to the satisfaction or waiver of certain conditions. For more information, see the section entitled “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

In addition, completion of the distribution is a condition to the Atlas Merger, and indirectly the APL Merger. For more information on the Atlas Merger, see the Proxy Statement.

 

 

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The following chart shows our organization and ownership after giving effect to the distribution and the related transactions, including the Atlas Merger and the APL Merger. All unit figures are approximate numbers and are based on the distribution of approximately 52.0 million common units of New Atlas to the Atlas Energy unitholders.

LOGO

Company Information

We were formed in Delaware in October 2011 to serve as the general partner of Atlas Resource Partners, L.P. Following the separation, we will hold all of Atlas Energy’s assets and businesses other than those related to its “Atlas Pipeline Partners” segment, in connection with the separation and distribution described in this information statement. The address of our principal executive offices is Park Place Corporate Center One, 1000 Commerce Drive, 4th Floor, Pittsburgh, PA 15275, and the phone number is (412) 489-0006. We intend to establish an Internet site at www.atlasenergy.com. Our website and the information contained on that site, or connected to that site, are not incorporated by reference into this information statement, and you should not rely on any such information in making an investment decision.

We own or have rights to use the trademarks, service marks and trade names that we use in conjunction with the operation of our business.

Cash Distributions

The amount of distributions we pay under our cash distribution policy and the decision to make any distribution will be determined by our board of directors, taking into account the terms of our amended and restated limited liability company agreement. The board of directors intends to adopt a cash distribution policy that will require, pursuant to our amended and restated limited liability company agreement, that we distribute all of our available cash quarterly to our members within 50 days following the end of each calendar quarter in accordance with their respective percentage interests.

 

 

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New Atlas believes, based on the assumptions and considerations discussed in the section entitled “Cash Distribution Policy—Estimated Initial Cash Available for Distribution” beginning on page 79, that upon completion of the distribution of the New Atlas common units, New Atlas’s initial quarterly distribution will, subject to proration as described below, be equal to $0.275 per common unit, or $1.10 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $14.4 million per quarter, or approximately $57.8 million per year. New Atlas’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77. We cannot assure you that any distributions will be declared or paid by us, and there is no guarantee of distributions at a particular level or of any distributions being made. We did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the twelve months ending December 31, 2015. For more information, see the section entitled “Cash Distribution Policy” beginning on page 76.

We expect to pay a prorated cash distribution for the first quarter that we are a publicly traded company. This prorated cash distribution will be paid for the period beginning on the distribution date for the New Atlas common units and ending on the last day of that fiscal quarter. Any cash distributions received by New Atlas from Atlas Resource Partners between the date of the most recent cash distribution to the Atlas Energy unitholders prior to the distribution date for the New Atlas common units and such distribution date will be included in New Atlas’s first cash distribution.

Our cash distribution policy will be consistent with the terms of our limited liability company agreement. Under our limited liability company agreement, available cash will be defined to mean generally, for each fiscal quarter, all cash on hand at the date of determination of available cash in respect of such quarter, less the amount of cash reserves established by our board of directors, which will not be subject to a cap, to:

 

    comply with applicable law;

 

    comply with any agreement binding upon us or our subsidiaries (exclusive of ARP and Lightfoot and their respective subsidiaries);

 

    provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future; or

 

    otherwise provide for the proper conduct of our business.

These reserves will not be restricted by magnitude, but only by type of future cash requirements with which they can be associated. Our available cash will also include cash on hand resulting from borrowings made after the end of the quarter. When our board of directors determines our quarterly distributions, it will consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to members will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

While our cash distribution policy, consistent with the terms of our limited liability company agreement, will require that we distribute all of our available cash quarterly, our cash distribution policy will be subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

    We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

    Our cash distribution policy will be, and ARP’s cash distribution policy is, subject to restrictions on distributions under any credit facility we enter into and under ARP’s credit facilities, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

 

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    Our board of directors will have the authority under our amended and restated limited liability company agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

 

    Our limited liability company agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

 

    Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

    We can issue additional units, including units that are senior to the common units, without the consent of our unitholders, and these additional units would dilute common unitholders’ ownership interests.

 

    Under Section 18-607 of the Delaware Limited Liability Company Act (the “Delaware Act”), we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Agreement to Be Bound by Limited Liability Company Agreement; Common Unit Voting Rights

By acquiring a common unit in the distribution or if you purchase or otherwise acquire 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. In voting their units, affiliates of our directors and officers will have no fiduciary duty or obligation whatsoever to us or to our other unitholders, including any duty to act in good faith or in the best interests of us or the other unitholders. Pursuant to our limited liability company agreement, as a common unitholder, your entitlement to vote on the following matters will be as set forth in the table below:

 

Matter

  

Common Unitholders’ Voting Rights

Election of the directors to our board of directors

   Plurality of votes cast by our unitholders.

Issuance of additional units

   No approval right subject to existing NYSE listing rules.

Amendment of our limited liability company agreement

   Certain amendments may be made by our board of directors without the approval of our unitholders. Other amendments generally require the approval of a majority of our outstanding voting units.

Merger of our company or the sale of all or substantially all of our assets

   A majority of our outstanding voting units in certain circumstances.

Dissolution of our company

   A majority of our outstanding voting units.

Continuation of our company after dissolution

   A majority of our outstanding voting units.

For more information, please see the section entitled “Our Limited Liability Company Agreement.”

Estimated Ratio of Taxable Income to Distributions

We estimate that a U.S. holder who receives our common units in the distribution and holds such common units from the distribution date through the record date for distributions for the period ending December 31,

 

 

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2015, will be allocated an amount of U.S. federal taxable income for that period that will be 20% or less of the cash distributed with respect to that period. We anticipate that after the taxable year ending December 31, 2015, the ratio of allocable taxable income to cash distributions to the unitholders will increase. Please read the summary in the section entitled “Certain U.S. Federal Income Tax Matters—Tax Consequences of Ownership of Our Common Units” beginning on page 264.

Reason for Furnishing this Information Statement

This information statement is being furnished solely to provide information to common unitholders of Atlas Energy who will receive our common units in the distribution. It is not and is not to be construed as an inducement or encouragement to buy or sell any of our securities. It does not contain a proxy and is not intended to constitute solicitation material under U.S. federal securities law. The information contained in this information statement is believed by us to be accurate as of the date set forth on its cover. Changes may occur after that date, and neither Atlas Energy nor New Atlas will update the information except in the normal course of their respective disclosure obligations and practices and as required by law.

 

 

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SUMMARY HISTORICAL AND UNAUDITED PRO FORMA COMBINED

FINANCIAL INFORMATION

The following table presents summary pro forma combined financial data for New Atlas. The summary combined statement of operations data for each of the fiscal years in the three-year period ended December 31, 2013 and the summary combined balance sheet data as of December 31, 2013 and 2012 were derived from New Atlas’s audited combined consolidated financial statements included elsewhere in this information statement. The summary combined statement of operations data for the nine months ended September 30, 2014 and 2013 and the summary combined balance sheet data as of September 30, 2014 have been derived from New Atlas’s unaudited combined consolidated interim financial statements included elsewhere in this information statement. The unaudited combined consolidated financial statements have been prepared on the same basis as the audited combined consolidated financial statements and, in our opinion, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the information set forth herein.

The summary pro forma combined statement of operations data for the nine months ended September 30, 2014 and 2013 and the year ended December 31, 2013, and the summary pro forma combined balance sheet data as of September 30, 2014, were derived from New Atlas’s unaudited pro forma combined financial statements included elsewhere in this information statement, which have been adjusted to give effect to the following transactions:

 

    the contribution by Atlas Energy to us of certain of the assets and liabilities that comprise our business;

 

    the issuance of 52.0 million of our common units, all of which will be distributed to holders of Atlas Energy common units. This number of common units is based upon the number of Atlas Energy common units expected to be outstanding on February 25, 2015 and a distribution ratio of one common unit of New Atlas for each common unit of Atlas Energy; and

 

    the impact of a separation and distribution agreement and other transaction agreements between us and Atlas Energy and the provisions contained therein.

The summary pro forma combined statements of operations data for the nine months ended September 30, 2014 and 2013 and the year ended December 31, 2013 assumes the separation and related transactions had occurred as of January 1, 2014, January 1, 2013 and January 1, 2013, respectively. The summary pro forma combined balance sheet data assumes the separation and related transactions occurred on September 30, 2014. The assumptions used and pro forma adjustments derived from such assumptions are based on currently available information, and we believe such assumptions are reasonable under the circumstances.

The summary pro forma combined financial data is not necessarily indicative of our results of operations or financial condition had the separation and our anticipated post-separation capital structure been completed on the dates assumed. Also, they may not reflect the results of operations or financial condition that would have resulted had we been operating as an independent, publicly traded company during such periods. In addition, they are not necessarily indicative of our future results of operations or financial condition. Further information regarding the pro forma adjustments listed above can be found within the “New Atlas Operations and Subsidiaries Unaudited Pro Forma Condensed Combined Financial Statements” section of this information statement beginning on page F-2.

The summary historical combined financial data presented below should be read in conjunction with New Atlas’s audited and unaudited interim combined consolidated financial statements and accompanying notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113. The summary pro forma combined financial data presented below should be read in conjunction with our unaudited pro forma combined financial statements included elsewhere in this information statement.

 

 

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The following table should be read together with our combined consolidated financial statements and notes beginning on page F-66).

 

    Historical     Pro Forma  
    Nine Months Ended
September 30,
    Years Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,
 
    2014     2013     2013     2012     2011     2014     2013     2013  

Revenues:

               

Gas and oil production

  $ 342,456      $ 176,190      $ 273,906      $ 92,901      $ 66,979      $ 388,457      $ 334,749      $  456,107   

Well construction and completion

    126,917        92,293        167,883        131,496        135,283        126,917        92,293        167,883   

Gathering and processing

    11,287        11,639        15,676        16,267        17,746        11,287        11,639        15,676   

Administration and oversight

    12,072        8,923        12,277        11,810        7,741        12,072        8,923        12,277   

Well services

    18,441        14,703        19,492        20,041        19,803        18,441        14,703        19,492   

Other, net

    1,167        (14,459     (14,135     (3,346     16,527        1,167        21        345   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

    512,340        289,289        475,099        269,169        264,079        558,341        462,328        671,780   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and expenses:

               

Gas and oil production

    134,590        64,837        100,178        26,624        17,100        149,984        129,883        173,877   

Well construction and completion

    110,363        80,255        145,985        114,079        115,630        110,363        80,255        145,985   

Gathering and processing

    11,900        13,767        18,012        19,491        20,842        11,900        13,767        18,012   

Well services

    7,525        7,009        9,515        9,280        8,738        7,525        7,009        9,515   

General and administrative

    63,487        73,037        89,957        75,475        27,688        50,722        47,140        60,034   

Chevron transaction expense

    —         —         —          7,670        —          —         —         —     

Depreciation, depletion and amortization

    177,513        86,392        139,916        52,582        31,938        186,387        117,227        175,115   

Asset impairment

    —         —         38,014        9,507        6,995        —         —         38,014   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

    505,378        325,297        541,577        314,708        228,931        516,881        395,281        620,552   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income (loss)

    6,962        (36,008     (66,478     (45,539     35,148        41,460        67,047        51,228   

Gain (loss) on asset sales and disposal

    (1,683     (2,035     (987     (6,980     90        (1,683     (2,035     (987

Interest expense

    (51,474     (24,704     (39,712     (4,548     (4,244     (61,955     (60,499     (79,834
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

  $ (46,195   $ (62,747   $ (107,177   $ (57,067   $ 30,994      $ (22,178   $ 4,513      $ (29,593
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Other financial data:

               

Adjusted EBITDA(1)

  $ 61,131      $ 39,300      $ 57,508      $ 37,009      $ 65,254      $ 61,131      $ 39,300      $ 57,508   

Balance sheet data (at period end):

               

Property, plant and equipment, net

  $ 2,728,650      $ 2,243,190      $ 2,186,683      $ 1,302,228      $ 525,454      $ 2,728,650       

Total assets

    3,153,276        2,494,571        2,455,870        1,526,652        732,641        3,153,962       

Total debt, including current portion

    1,431,522        1,098,279        1,091,959        357,050        —          1,438,022       

Total equity

    1,330,655        1,138,544        1,043,996        868,804        485,348        1,324,841       

Cash flow data:

               

Net cash provided by (used in) operating activities

  $ (26,583   $ (78,459   $ 3,841      $ 13,524      $ 83,410         

Net cash used in investing activities

    (671,897     (990,279     (1,053,524     (837,825     (57,984      

Net cash provided by financing activities

    744,592        1,047,037        1,037,038        792,863        29,282         

Capital expenditures

    (162,726     (205,827     (267,480     (127,226     (47,324      

Operating data:(2)

               

Net production:

               

Natural gas (Mcfd)

    238,158        137,725        163,992        69,408        31,403         

Oil (Bpd)

    2,882        1,301        1,336        330        307         

Natural gas liquids (Bpd)

    3,807        3,441        3,476        974        444         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

Total (Mcfed)

    278,290        166,178        192,866        77,232        35,912         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

Average sales price:

               

Natural gas (per Mcf):(3)

               

Total realized price, after hedge(3)

  $ 3.79      $ 3.39      $ 3.48      $ 3.29      $ 4.98         

Total realized price, before hedge(3)

  $ 4.08      $ 3.20      $ 3.25      $ 2.60      $ 4.53         

Oil (per Bbl):(3)

               

Total realized price, after hedge

  $ 89.87      $ 91.19      $ 91.02      $ 94.02      $ 89.70         

Total realized price, before hedge

  $ 93.46      $ 96.50      $ 95.86      $ 91.32      $ 89.07         

Natural gas liquids (per Bbl):(3)

               

Total realized price, after hedge

  $ 30.56      $ 28.01      $ 28.71      $ 31.97      $ 48.26         

Total realized price, before hedge

  $ 32.14      $ 28.52      $ 29.43      $ 31.97      $ 48.26         

Production costs (per Mcfe):

               

Lease operating expenses(4)

  $ 1.26      $ 1.11      $ 1.08      $ 0.82      $ 1.09         

Production taxes

    0.27        0.17        0.18        0.12        0.10         

Transportation and compression

    0.26        0.22        0.25        0.24        0.43         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

Total production costs

  $ 1.80      $ 1.51      $ 1.50      $ 1.19      $ 1.61         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

       

 

 

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(1)  We define Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion and amortization, plus certain non-cash items such as compensation expenses associated with unit issuances to our directors and employees. Adjusted EBITDA is not a measure of performance calculated in accordance with GAAP. Although not prescribed under GAAP, we believe the presentation of Adjusted 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. Adjusted 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. Adjusted EBITDA, as we calculate it, may not be comparable to Adjusted EBITDA measures reported by other companies. Adjusted EBITDA is also a financial measurement that, with certain negotiated adjustments, will be utilized within our proposed new credit facility. In addition, Adjusted EBITDA does not represent funds available for discretionary use or the payment of distributions. The following reconciles our net income to Adjusted EBITDA for the periods indicated:

 

    Historical     Pro Forma  
    Nine Months Ended
September 30,
    Years Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,
 
    2014     2013     2013     2012     2011     2014     2013     2013  

Net income (loss)

  $ (46,195   $ (62,747   $ (107,177   $ (57,067   $ 30,994      $ (22,178   $ 4,513      $ (29,593

Atlas Resource net (income) loss attributable to New Atlas owners

    1,323        19,766        32,463        34,718        (19,899     (6,459     (1,396     8,312   

Development Subsidiary net loss attributable to New Atlas owners

    3,560        3,354        4,036        —          —          3,560        3,354        4,036   

Loss (income) attributable to non-controlling interests

    33,828        31,484        58,389        17,184        —          13,364        (24,727     (4,231

New Atlas interest expense

    8,446        2,559        5,388        353        4,244        12,675        12,672        14,575   

New Atlas depreciation, depletion and amortization

    4,987        1,331        3,020        —          1,069        4,987        1,331        3,020   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

EBITDA

    5,949        (4,253     (3,881     (4,812     16,408        5,949        (4,253     (3,881

Cash distributions earned from ARP

    54,564        41,123        58,347        31,270        —          54,564        41,123        58,347   

Cash distributions earned from Development Subsidiary

    133        —          26        —          —          133        —          26   

E&P Operations Adjusted EBITDA prior to spinoff on March 5, 2012

    —          —          —          9,111        49,182        —          —          —     

Acquisition and related costs

    77        1,831        2,151        2,000        —          77        1,831        2,151   

Premiums paid on swaption derivative contracts

    —          2,287        2,287        —          —          —          2,287        2,287   

Loss on asset sales and disposal

    (3     —          —          —          (3     (3     —          —     

Other

    411        (1,688     (1,422     (560     (333     411        (1,688     (1,422
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

  $ 61,131      $ 39,300      $ 57,508      $ 37,009      $ 65,254      $ 61,131      $ 39,300      $ 57,508   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(2)  “Mcf” represents thousand cubic feet; “Mcfe” represents thousand cubic feet equivalents; “Mcfd” represents thousand cubic feet per day; “Mcfed” represents thousand cubic feet equivalents per day; and “Bbls” and “Bpd” represent barrels and barrels per day.
(3)  Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011. Including the effect of this subordination, the average realized gas sales price was $3.68 per Mcf ($3.96 per Mcf before the effects of financial hedging) and $3.12 per Mcf ($2.93 per Mcf before the effects of financial hedging) for the nine months ended September 30 2014 and 2013, respectively, and $3.23 per Mcf ($3.00 per Mcf before the effects of financial hedging), $2.76 per Mcf ($2.08 per Mcf before the effects of financial hedging) and $4.28 per Mcf ($3.83 per Mcf before the effects of financial hedging) for years ended December 31, 2013, 2012 and 2011, respectively.
(4)  Excludes the effects of ARP’s proportionate share of lease operating expenses associated with subordination of its production revenue to investor partners within its Drilling Partnerships for the nine months ended September 30, 2014 and 2013 and the years ended December 31, 2013, 2012 and 2011. Including the effects of these costs, ARP’s lease operating expenses per Mcfe were $1.25 per Mcfe ($1.78 per Mcfe for total production costs) and $1.04 per Mcfe ($1.43 per Mcfe for total production costs) for the nine months ended September 30, 2014 and 2013, respectively and $1.00 per Mcfe ($1.42 per Mcfe for total production costs), $0.58 per Mcfe ($0.94 per Mcfe for total production costs) and $0.80 per Mcfe ($1.41 per Mcfe for total production costs) for the years ended December 31, 2013, 2012 and 2011, respectively.

 

 

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SUMMARY RESERVE DATA

The following tables show our estimated net proved reserves based on reserve reports prepared by our independent petroleum engineers. You should refer to “Risk Factors” beginning on page 31, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113, “Business—Natural Gas and Oil Reserves” beginning on page 170 and the summary reserve reports included as Exhibits 99.2 and 99.3 to the registration statement of which this document forms a part in evaluating the material presented below.

 

     December 31,  
     2013      2012  

Reserve data:

     

Estimated net proved reserves(1):

     

Natural gas reserves (MMcf):

     

Proved developed reserves

     766,872         338,655   

Proved undeveloped reserves(2)

     236,907         235,119   
  

 

 

    

 

 

 

Total proved reserves of natural gas

  1,003,779      573,774   

Oil reserves (MBbl):

Proved developed reserves

  3,459      3,400   

Proved undeveloped reserves(2)

  11,530      5,469   
  

 

 

    

 

 

 

Total proved reserves of oil

  14,989      8,869   

NGL reserves (MBbl)(1):

Proved developed reserves

  7,676      7,885   

Proved undeveloped reserves(2)

  11,281      8,177   
  

 

 

    

 

 

 

Total proved reserves of NGL

  18,957      16,062   

Total proved reserves (MMcfe)

  1,207,455      723,359   
  

 

 

    

 

 

 

Standardized measure of discounted future cash flows (in thousands)(3)

$ 1,079,291    $ 623,676   
  

 

 

    

 

 

 

Reserve natural gas and oil prices:

Unadjusted prices(4):

Natural gas (per MMBtu)

$ 3.67    $ 2.76   

Oil (per Bbl)

$ 96.78    $ 94.71   

Natural gas liquids (per Bbl)

$ 30.10    $ 33.91   

Average Realized Prices, Before Hedge(5):

Natural gas (per Mcf)

$ 3.25    $ 2.53   

Oil (per Bbl)

$ 95.86    $ 92.26   

Natural gas liquids (per Bbl)

$ 29.43    $ 31.97   

 

(1)  “MMcf” represents million cubic feet; “MMBtu” represents million British thermal units; “MMcfe” represents million cubic feet equivalents; and “MBbl” represents thousand barrels. Oil and NGLs are converted to gas equivalent basis (“Mcfe”) at the rate of one barrel to 6 Mcf of natural gas. Mcf is defined as one thousand cubic feet.
(2)  ARP’s ownership in these reserves is subject to reduction as it generally makes capital contributions, which includes leasehold acreage associated with ARP’s proved undeveloped reserves, to its Drilling Partnerships in exchange for an equity interest in these partnerships, which is approximately 30%, which effectively will reduce ARP’s ownership interest in these reserves from 100% to its respective ownership interest as ARP makes these contributions.
(3) 

Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC without giving effect to non-property related expenses, such as general and administrative expenses, interest and

 

 

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  income tax expenses, or to depletion, depreciation and amortization. The future cash flows are discounted using an annual discount rate of 10%. Standardized measure does not give effect to commodity derivative contracts. Because we and ARP are limited liability companies or limited partnerships, no provision for federal or state income taxes has been included in the December 31, 2013 and 2012 calculations of standardized measure, which is, therefore, the same as the PV-10 value. Standardized measure for the years ended December 31, 2013 and 2012 includes approximately $2.0 million and $3.8 million related to the present value of future cash flows from plugging and abandonment of wells, including the estimated salvage value. These amounts were not included in the summary reserve reports that appear in Exhibits 99.2 and 99.3 to the registration statement of which this information statement forms a part.
(4)  “Mcf” represents thousand cubic feet; and “Bbl” represents barrels.
(5)  Excludes the impact of subordination of ARP’s production revenue to investor partners within its Drilling Partnerships for years ended December 31, 2013 and 2012. Including the effect of this subordination, the average realized gas sales price was $3.00 per Mcf before the effects of financial hedging and $2.08 per Mcf before the effects of financial hedging for years ended December 31, 2013 and 2012, respectively.

 

 

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RISK FACTORS

You should carefully consider each of the following risk factors and all of the other information set forth in this information statement. The risk factors generally have been separated into seven groups: (1) risks relating to our business, (2) risks relating to our and ARP’s exploration and production operations, (3) risks relating to ARP’s drilling partnerships, (4) risks relating to the separation, (5) risks relating to the ownership of our common units, (6) tax risks to unitholders and (7) risks relating to our conflicts of interest. Based on the information currently known to us, we believe that the following information identifies the most significant risk factors affecting our company in each of these categories of risks. However, the risks and uncertainties our company faces are not limited to those set forth in the risk factors described below. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also adversely affect our business. In addition, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods. For information on risks relating to the Atlas Merger, please see the Proxy Statement.

If any of the following risks and uncertainties develops into actual events, these events could have a material adverse effect on our business, financial condition or results of operations. In such case, the trading price of our common units could decline.

Risks Relating to Our Business

Our primary assets are our partnership interests, including the IDRs, in ARP and, therefore, our cash flow is dependent on the ability of ARP to make distributions in respect of those partnership interests.

The amount of cash that ARP can distribute to its partners, including us, each quarter principally depends upon the amount of cash it generates from its operations, which will fluctuate from quarter to quarter and will depend on, among other things:

 

    the amount of natural gas and oil ARP produces;

 

    the price at which ARP sells its natural gas and oil;

 

    the level of ARP’s operating costs;

 

    ARP’s ability to acquire, locate and produce new reserves;

 

    the results of ARP’s hedging activities;

 

    the level of ARP’s interest expense, which depends on the amount of ARP’s indebtedness and the interest payable on it; and

 

    the level of ARP’s capital expenditures.

In addition, the actual amount of cash that ARP will have available for distribution will also depend on other factors, some of which are beyond ARP’s control, including:

 

    ARP’s ability to make working capital borrowings to pay distributions;

 

    the cost of acquisitions, if any;

 

    fluctuations in ARP’s working capital needs;

 

    timing and collectability of receivables;

 

    restrictions on distributions imposed by lenders;

 

    the strength of financial markets and our ability to access capital or borrow funds; and

 

    the amount, if any, of cash reserves established by ARP’s general partner in its discretion for the proper conduct of ARP’s business.

 

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Because of these factors, we cannot guarantee that ARP will have sufficient available cash to pay a specific level of cash distributions to its partners. You should also be aware that the amount of cash that ARP has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, ARP may make cash distributions during periods when it records net losses and may not make cash distributions during periods when it records net income.

We may not have sufficient cash to pay distributions.

Our ability to fund our operations, pay debt service and to make distributions to our unitholders may fluctuate based on the level of distributions ARP makes to its partners and the cash flows generated by our assets.

Our ability to distribute cash to our unitholders will be limited by a number of factors, including:

 

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

 

    restrictions on distributions contained in any future debt agreements;

 

    our general and administrative expenses, including expenses we incur as a result of being a public company;

 

    expenses of our subsidiaries other than ARP, including tax liabilities of our corporate subsidiaries, if any; and

 

    reserves that we believe are prudent for us to maintain for the proper conduct of our business or to provide for future distributions.

We cannot guarantee that in the future we will be able to pay distributions or that any distribution we make will be at or above our previous quarterly distribution levels. The actual amount of cash that is available for distribution to our unitholders will depend on numerous factors, many of which are beyond our control.

The assumptions underlying the forecast of cash distributions that we include in the section entitled “Cash Distribution Policy” are inherently uncertain and subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause our actual cash distributions to differ materially from our forecast, and we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period.

The forecast of cash available for distribution set forth in the section entitled “Cash Distribution Policy” includes our forecast of our results of operations, EBITDA, adjusted EBITDA and distributable cash flow for the twelve months ending December 31, 2015. Our ability to pay the full initial quarterly distribution in the forecast period is based on a number of assumptions that may not prove to be correct and that are discussed in the section entitled “Cash Distribution Policy—Significant Forecast Assumptions.” Our financial forecast has been prepared by management and we have neither received nor requested an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties, including those discussed in this information statement, which could cause there to be material differences between our forecast and our actual results. In addition, we did not use quarter-by-quarter estimates in concluding that there would be sufficient cash available for distribution to pay the initial quarterly distribution on all of our common units during the forecast period. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate, and the market price of our common units may decline materially.

 

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Our ability to meet our future financial needs may be adversely affected by our cash distribution policy.

Our cash distribution policy, which is consistent with our limited liability company agreement, will require us to distribute all of our available cash quarterly. Given that our cash distribution policy will be to distribute available cash and not retain it, we may not have enough cash to meet our needs if any of the following events occur:

 

    an increase in our operating expenses;

 

    an increase in general and administrative expenses;

 

    an increase in principal and interest payments on our outstanding debt; or

 

    an increase in working capital requirements.

If distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Our distributions to our common unitholders will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Economic conditions and instability in the financial markets could negatively affect our and our subsidiaries’ businesses which, in turn, could affect the cash we have to make distributions to our unitholders.

Our and our subsidiaries’ operations are affected by the financial markets and related effects in the global financial system. The consequences of an economic recession and the effects of the financial crisis include a lower level of economic activity and increased volatility in energy prices. This may result in a decline in energy consumption and lower market prices for oil and natural gas and has previously resulted in a reduction in drilling activity in our subsidiaries’ service areas. Any of these events may adversely affect our and our subsidiaries’ revenues and ability to fund capital expenditures and, in the future, may affect the cash that we have available to fund our operations, pay required debt service on our credit facilities and make distributions to our unitholders.

Potential instability in the financial markets, as a result of recession or otherwise, can cause volatility in the markets and may affect our and our subsidiaries’ ability to raise capital and reduce the amount of cash available to fund operations. We cannot be certain that additional capital will be available to us or our subsidiaries to the extent required and on acceptable terms. Disruptions in the capital and credit markets could negatively affect our and our subsidiaries’ access to liquidity needed for our businesses and affect flexibility to react to changing economic and business conditions. We and our subsidiaries may be unable to execute our growth strategies, take advantage of business opportunities or to respond to competitive pressures, any of which could negatively affect our business.

A weakening of the current economic situation could have an adverse impact on producers, key suppliers or other customers, or on our or our subsidiaries’ lenders, causing them to fail to meet their obligations. Market conditions could also affect our or our subsidiaries’ derivative instruments. If a counterparty is unable to perform its obligations and the derivative instrument is terminated, our and our subsidiaries’ cash flow and ability to pay distributions could be affected which in turn affects the amount of distributions that we are able to make to our unitholders. The uncertainty and volatility surrounding the global financial system may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

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

Pricing for natural gas, NGLs and oil has been volatile and unpredictable for many years. To limit exposure to changing natural gas and oil prices, we and our subsidiaries may use financial and physical hedges for

 

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production. Physical hedges are not deemed hedges for accounting purposes because they require firm delivery of natural gas and are considered normal sales of natural gas. We and our subsidiaries generally limit these arrangements to smaller quantities than those projected to be available at any delivery point.

In addition, we and our subsidiaries may enter into financial hedges, which may include purchases of regulated NYMEX futures and options contracts and non-regulated over-the-counter futures contracts with qualified counterparties in compliance with the Dodd-Frank Wall Street Reform and Consumer Protection Act, which we refer to as the Dodd-Frank Act. The futures contracts are commitments to purchase or sell hydrocarbons at future dates and generally cover one-month periods for up to six years in the future. The over-the-counter derivative contracts are typically cash settled by determining the difference in financial value between the contract price and settlement price and do not require physical delivery of hydrocarbons.

These hedging arrangements may reduce, but will not eliminate, the potential effects of changing commodity prices on cash flow from operations for the periods covered by the hedging arrangement. Furthermore, while intended to help reduce the effects of volatile commodity prices, such transactions, depending on the hedging instrument used, may limit potential gains if commodity prices were to rise substantially over the price established by the hedge. If, among other circumstances, production is substantially less than expected, the counterparties to the futures contracts fail to perform under the contracts or a sudden, unexpected event materially changes commodity prices, we and our subsidiaries may be exposed to the risk of financial loss. In addition, it is not always possible to engage in a derivative transaction that completely mitigates exposure to commodity prices and interest rates. The financial statements may reflect a gain or loss arising from an exposure to commodity prices and interest rates for which we and our subsidiaries are unable to enter into a completely effective hedge transaction.

Due to the accounting treatment of derivative contracts, increases in prices for natural gas, crude oil and NGLs could result in non-cash balance sheet reductions and non-cash losses in our statement of operations.

With the objective of enhancing the predictability of future revenues, from time to time we and ARP enter into natural gas, NGLs and crude oil derivative contracts. We and our subsidiaries account for these derivative contracts by applying the mark-to-market accounting treatment required for these derivative contracts. We and our subsidiaries could recognize incremental derivative liabilities between reporting periods resulting from increases or decreases in reference prices for natural gas, crude oil and NGLs, which could result in the recognition of a non-cash loss in the consolidated combined statements of operations and a consequent non-cash decrease in equity between reporting periods. Any such decrease could be substantial. In addition, we and our subsidiaries may be required to make cash payments upon the termination of any of these derivative contracts.

Regulations adopted by the Commodity Futures Trading Commission could have an adverse effect on our and our subsidiaries’ ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our and their business.

The Dodd-Frank Act is intended to change fundamentally the way swap transactions are entered into, transforming an over-the-counter market in which parties negotiate directly with each other into a regulated market in which most swaps are to be executed on registered exchanges or swap execution facilities and cleared through central counterparties. These statutory requirements must be implemented through regulation, primarily through rules adopted by the Commodity Futures Trading Commission. Many market participants will be newly regulated as swap dealers or major swap participants, with new regulatory capital requirements and other regulations that impose business conduct rules and mandate how they hold collateral or margin for swap transactions. All market participants will be subject to new reporting and recordkeeping requirements. The new regulations may require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our existing or future derivative activities. As a commercial end-user which uses

 

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swaps to hedge or mitigate commercial risk, rather than for speculative purposes, we are permitted to opt out of the clearing and exchange trading requirements, but we could nevertheless be exposed to greater liquidity and credit risk with respect to our hedging transactions if we do not use cleared and exchange-traded swaps.

Counterparties to our derivative instruments that are federally insured depository institutions are required to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new regulations could significantly increase the cost of derivative contracts; materially alter the terms of derivative contracts; reduce the availability of derivatives to protect against risks we and ARP encounter; reduce our and ARP’s ability to monetize or restructure our and ARP’s derivative contracts in existence at that time; and increase our and ARP’s exposure to less creditworthy counterparties. If we and ARP reduce or change the way we use derivative instruments as a result of the legislation or regulations, our and ARP’s results of operations may become more volatile and cash flows may be less predictable, which could adversely affect our and ARP’s ability to plan for and fund capital expenditures. The legislation was also intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our and ARP’s revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our and ARP’s consolidated financial position, results of operations and/or cash flows.

The scope and costs of the risks involved in our or our subsidiaries making acquisitions may prove greater than estimated at the time of the acquisition, and our subsidiaries may be unsuccessful in integrating the operations from future acquisitions and realizing the anticipated benefits of these acquisitions.

Any acquisition involves potential risks, including, among other things:

 

    the validity of our assumptions about reserves, future production, revenues, processing volumes, capital expenditures and operating costs;

 

    an inability to successfully integrate the businesses acquired;

 

    a decrease in liquidity by using a portion of available cash or borrowing capacity under respective revolving credit facilities to finance acquisitions;

 

    a significant increase in interest expense or financial leverage if additional debt to finance acquisitions is incurred;

 

    the assumption of unknown environmental or title and other liabilities, losses or costs for which we or our subsidiary are not indemnified or for which the indemnity is inadequate;

 

    the diversion of management’s attention from other business concerns and increased demand on existing personnel;

 

    the incurrence of other significant charges, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges;

 

    unforeseen difficulties encountered in operating in new geographic areas;

 

    customer or key employee losses at the acquired businesses; and

 

    the failure to realize expected growth or profitability.

The scope and cost of these risks may be materially greater than estimated at the time of the acquisition. Our future acquisition costs may also be higher than those we have achieved historically. Any of these factors could adversely affect future growth and the ability to make or increase distributions. In addition, the integration of

 

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previously independent operations can be a complex, costly and time-consuming process. The difficulties of combining these systems, as well as any operations we or our subsidiaries may acquire in the future, include, among other things:

 

    operating a significantly larger combined entity;

 

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

 

    integrating personnel with diverse business backgrounds and organizational cultures;

 

    consolidating operational and administrative functions;

 

    integrating internal controls, compliance under the Sarbanes-Oxley Act of 2002 and other corporate governance matters;

 

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

 

    customer or key employee loss from the acquired businesses;

 

    a significant increase in indebtedness; and

 

    potential environmental or regulatory liabilities and title problems.

Costs incurred and liabilities assumed in connection with an acquisition and increased capital expenditures and overhead costs incurred to expand operations could harm our subsidiaries’ businesses or future prospects, and result in significant decreases in gross margin and cash flows.

ARP may issue additional units, which may increase the risk of not having sufficient available cash to make distributions at prior per unit distribution levels.

ARP has wide discretion to issue additional limited partner units, including units that rank senior to its common units and the incentive distribution rights as to quarterly cash distributions, on the terms and conditions established by its general partner. The payment of distributions on additional ARP common units may increase the risk of ARP being unable to make distributions at its prior per unit distribution levels. To the extent new ARP limited partner units are senior to the ARP common units and the incentive distribution rights, their issuance will increase the uncertainty of the payment of distributions on the common units and the incentive distribution rights. Neither the common units nor the incentive distribution rights are entitled to any arrearages from prior quarters.

Reduced incentive distributions from ARP will disproportionately affect the amount of cash distributions to which we are entitled.

We are entitled to receive incentive distributions from ARP with respect to any particular quarter only if ARP distributes more than $0.46 per common unit for such quarter. Our incentive distribution rights in ARP entitle us to receive percentages increasing up to 48% of all cash distributed by ARP. Distribution by ARP above $0.60 per common unit per quarter would result in our incremental cash distributions to be the maximum 48%. Our percentage of the incremental cash distributions reduces from 48% to 23% if ARP’s distribution is between $0.51 and $0.60, and to 13% if ARP’s distribution is between $0.47 and $0.50. As a result, lower quarterly cash distributions per share from ARP have the effect of disproportionately reducing the amount of all incentive distributions that we receive as compared to cash distributions we receives on our 2.0% general partner interest in ARP.

We, as ARP’s general partner, may limit or modify the incentive distributions we are entitled to receive from ARP in order to facilitate the growth strategy of ARP. Our board of directors can give this consent without a vote of our unitholders.

We are ARP’s general partner and own the incentive distribution rights in ARP that entitle us to receive increasing percentages, of any cash distributed by ARP as it reaches certain target distribution levels in any quarter. To facilitate acquisitions by ARP, we may elect to limit the incentive distributions we are entitled to

 

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receive with respect to a particular acquisition or unit issuance contemplated by ARP. This is because a potential acquisition might not be accretive to ARP’s common unitholders as a result of the significant portion of that acquisition’s cash flows, which would be paid as incentive distributions to us. By limiting the level of incentive distributions in connection with a particular acquisition or issuance of units of ARP, the cash flows associated with that acquisition could be accretive to ARP’s common unitholders as well as substantially beneficial to us. In doing so, our board of directors (which is also ARP’s board of directors) would be required to consider obligations to ARP’s investors and its obligations to us.

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

We currently manage ARP through our ownership of its general partner interest. ARP’s partnership agreement gives common unitholders of ARP the right to remove the general partner of ARP upon the affirmative vote of holders of 66 2/3% of ARP’s outstanding common units. If we were removed as general partner of ARP, we would receive cash or common units in exchange for our 2.0% general partner interest and the incentive distribution rights, but we would lose the ability to manage ARP or receive future distributions. Although the common units or cash we would receive are intended under the terms of ARP’s partnership agreement to fully compensate us in the event such an exchange is required, the value of these common units or investments we make with the cash over time may not be equivalent to the value of the general partner interest and the incentive distribution rights had we retained them.

If we are not fully reimbursed or indemnified for obligations and liabilities we incur in managing the business and affairs of ARP, the value of our common units could decline.

In our capacity as the general partner of ARP, we may make expenditures on ARP’s behalf for which we will seek reimbursement from ARP. In addition, under Delaware partnership law, we have, in our capacity as ARP’s general partner, unlimited liability for the obligations of ARP, such as ARP’s debts and environmental liabilities, except for those contractual obligations of ARP that are expressly made without recourse to the general partner. To the extent we incur obligations on behalf of ARP, we are entitled to be reimbursed or indemnified by ARP. If ARP is unable or unwilling to reimburse or indemnify us, we may be unable to satisfy these liabilities or obligations, which would reduce the value of our common units.

If in the future we cease to manage and control ARP through our ownership of its general partner interests, we may be deemed to be an investment company.

If we cease to manage and control ARP and are deemed to be an investment company under the Investment Company Act of 1940, we would either have to register as an investment company under the Investment Company Act of 1940, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, such as the purchase and sale of securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

If we had to register as an investment company, we would also be unable to qualify as a partnership for U.S. federal income tax purposes and would be treated as a corporation for U.S. federal income tax purposes. We would pay U.S. federal income tax on our taxable income at the corporate tax rate, distributions to you would generally be taxed again as corporate distributions and none of our income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced, which would result in a material reduction in distributions to

 

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you and a reduction in the value of our common units. For a discussion of the U.S. federal income tax implications if we were treated as a corporation in any taxable year, please see the section entitled “Certain U.S. Federal Income Tax Matters—Partnership Status.”

Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for our or ARP’s services.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the earth’s atmosphere and other climate changes, the U.S. Environmental Protection Agency, or “EPA,” adopted regulations under existing provisions of the federal Clean Air Act that require entities that produce certain gases to inventory, monitor and report such gases. The EPA also adopted rules to regulate greenhouse gas emissions through traditional major source construction and operating permit programs. The EPA confirmed the permitting thresholds in July 2012. These permitting programs require consideration of and, if deemed necessary, implementation of the best available control technology to reduce greenhouse gas emissions, which could result in us or ARP incurring additional costs for emissions control and higher costs of doing business.

Risks Relating to Our and ARP’s Exploration and Production Operations

If commodity prices decline significantly, our cash flow from operations will decline.

Our revenue, profitability and cash flow substantially depend upon the prices and demand for natural gas and oil. The natural gas, NGLs 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, NGLs and oil prices will have a significant impact on the value of our and ARP’s reserves and on our cash flow. Prices for natural gas, NGLs and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas, NGLs or oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

    the level of domestic and foreign supply and demand;

 

    the price and level of foreign imports;

 

    the level of consumer product demand;

 

    weather conditions and fluctuating and seasonal demand;

 

    overall domestic and global economic conditions;

 

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

 

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

 

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

 

    technological advances affecting energy consumption;

 

    domestic and foreign governmental relations, regulations and taxation;

 

    the impact of energy conservation efforts;

 

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

 

    the price and availability of alternative fuels.

In the past, the prices of natural gas, NGLs and oil have been extremely volatile, and we expect this volatility to continue. During the year ended December 31, 2013, the NYMEX Henry Hub natural gas index price ranged

 

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from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $110.53 per Bbl to a low of $86.68 per Bbl. During the year ended December 31, 2014, the NYMEX Henry Hub natural gas index price ranged from a high of $7.92 per MMBtu to a low of $2.75 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $107.62 per Bbl to a low of $53.27 per Bbl. Between January 1, 2015 and January 29, 2015, the NYMEX Henry Hub natural gas index price ranged from a high of $3.29 per MMBtu to a low of $2.88 per MMBtu, and West Texas Intermediate oil prices ranged from a high of $52.69 per Bbl to a low of $44.45 per Bbl.

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

We and ARP operate in a highly competitive environment for acquiring properties and other natural gas and oil companies, attracting capital through ARP’s Drilling Partnerships, contracting for drilling equipment and securing trained personnel. Our and ARP’s competitors may be able to pay more for natural gas, NGLs and oil properties and drilling equipment and to evaluate, bid for and purchase a greater number of properties than our and/or ARP’s financial or personnel resources permit. Moreover, competitors for investment capital may have better track records in their programs, lower costs or stronger relationships with participants in the oil and gas investment community than we or ARP have. All of these challenges could make it more difficult for us and ARP to execute our and its growth strategy. We and ARP may not be able to compete successfully in the future in acquiring leasehold acreage or prospective reserves or in raising additional capital.

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

Shortages of drilling rigs, equipment and crews, or the costs required to obtain the foregoing in a highly competitive environment, could impair our and ARP’s operations and results.

Increased demand for drilling rigs, equipment and crews, due to increased activity by participants in our and ARP’s primary operating areas or otherwise, can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and oil field equipment and services could restrict our and ARP’s ability to drill the wells and conduct the operations that we or it currently have planned. Any delay in the drilling of new wells or significant increase in drilling costs could reduce our and ARP’s revenues.

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

Our and ARP’s key operating project areas are located in active drilling areas in the Arkoma Basin, Mississippi Lime, Marble Falls, Utica Shale and Marcellus Shale, and many of our and ARP’s leases are in areas that have already been partially depleted or drained by earlier offset drilling. This may inhibit our and ARP’s ability to find economically recoverable quantities of natural gas in these areas.

Our and ARP’s operations require substantial capital expenditures to increase our and its asset base. If we or ARP are unable to obtain needed capital or financing on satisfactory terms, our and ARP’s asset base will decline, which could cause revenues to decline and affect its and our ability to pay distributions.

The natural gas and oil industry is capital intensive. Because we expect that we will distribute our available cash to our unitholders each quarter in accordance with the terms of our limited liability company agreement, we expect that we will rely primarily on external financing sources such as commercial bank borrowings and the issuance of debt and equity securities to fund any expansion and investment capital expenditures. If we or ARP are

 

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unable to obtain sufficient capital funds on satisfactory terms with capital raised through equity and debt offerings, cash flow from operations, bank borrowings and the Drilling Partnerships, we and ARP may be unable to increase or maintain our or its inventory of properties and reserve base, or be forced to curtail drilling or other activities. This could cause ARP’s and our revenues to decline and diminish its and our ability to service any debt that it or we may have at such time. If we or ARP do not make sufficient or effective expansion capital expenditures, including with funds from third-party sources, we and ARP will be unable to expand our business operations, and may not generate sufficient revenue or have sufficient available cash to pay distributions on its or our units.

We and ARP depend on certain key customers for sales of our and its natural gas, crude oil and NGLs. To the extent that these customers reduce the volumes of natural gas, crude oil and NGLs they purchase or process from us or ARP, or cease to purchase or process natural gas, crude oil and NGLs from us or ARP, our and ARP’s revenues and cash available for distribution could decline.

We and ARP market the majority of our and its natural gas production to gas marketers directly or to third-party plant operators who process and market our and ARP’s gas. Crude oil produced from our and ARP’s wells flows directly into leasehold storage tanks where it is picked up by an oil company or a common carrier acting for an oil company. Natural gas liquids are extracted from the natural gas stream by processing and fractionation plants enabling the remaining “dry” gas to meet pipeline specifications for transport or sale to end users or marketers operating on the receiving pipeline. To the extent these and other key customers reduce the amount of natural gas, crude oil and NGLs they purchase from us or ARP, our and ARP’s revenues and cash available for distributions to unitholders could temporarily decline in the event it is unable to sell to additional purchasers.

An increase in the differential between the NYMEX or other benchmark prices of oil and natural gas and the wellhead price that we or ARP receive for our or its production could significantly reduce our or its cash available for distribution and adversely affect our or its financial condition.

The prices that we or ARP receive for our oil and natural gas production sometimes reflect a discount to the relevant benchmark prices, such as NYMEX. The difference between the benchmark price and the price that we or ARP receive is called a differential. Increases in the differential between the benchmark prices for oil and natural gas and the wellhead price that we or ARP receive could significantly reduce our cash available for debt service and adversely affect our or ARP’s financial condition. We and ARP use the relevant benchmark price to calculate our hedge positions, and in certain areas, we and ARP do not have any commodity derivative contracts covering the amount of the basis differentials we experience in respect of our production. As such, we and ARP will be exposed to any increase in such differentials, which could adversely affect our results of operations.

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

As of September 30, 2014, none of the leases covering our approximately 29,173 net undeveloped acres, or 0.0%, are scheduled to expire on or before December 31, 2014, while leases covering approximately 8,418 of ARP’s 789,030 net undeveloped acres, or 1.1%, are scheduled to expire on or before December 31, 2014. An additional 4.7% and 0.7% of ARP’s net undeveloped acres are scheduled to expire in each of the years 2015 and 2016, respectively. If we or ARP are unable to renew these leases or any leases scheduled for expiration beyond their expiration date, on favorable terms, we or ARP will lose the right to develop the acreage that is covered by an expired lease, which would reduce our or ARP’s cash flows from operations.

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

Our and ARP’s drilling activities are subject to many risks, including the risk that we or ARP will not discover commercially productive reservoirs. Drilling for natural gas and oil can be uneconomic, not only from

 

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dry holes, but also from productive wells that do not produce sufficient revenues to be commercially viable. In addition, our and ARP’s drilling and producing operations may be curtailed, delayed or canceled as a result of other factors, including:

 

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

 

    unexpected operational events and drilling conditions;

 

    adverse weather conditions;

 

    facility or equipment malfunctions;

 

    title problems;

 

    pipeline ruptures or spills;

 

    compliance with environmental and other governmental requirements;

 

    unusual or unexpected geological formations;

 

    formations with abnormal pressures;

 

    injury or loss of life;

 

    environmental accidents such as gas leaks, ruptures or discharges of toxic gases, brine or well fluids into the environment or oil leaks, including groundwater contamination;

 

    fires, blowouts, craterings and explosions; and

 

    uncontrollable flows of natural gas or well fluids.

Any one or more of these factors could reduce or delay our or ARP’s receipt of drilling and production revenues, thereby reducing our or ARP’s earnings, and could reduce revenues in one or more of ARP’s Drilling Partnerships, which may make it more difficult to finance ARP’s drilling operations through sponsorship of future partnerships. Any of these events can also cause substantial losses, personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination, loss of wells and regulatory penalties.

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

The physical effects of climatic change have the potential to damage facilities, disrupt operations and production activities and cause us and ARP to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to facilities from powerful winds or rising waters in low lying areas, disruption of production activities either because of climate-related damages to facilities or costs of operation potentially rising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on financing and operations by disrupting the transportation or process-related services

 

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provided by midstream companies, service companies or suppliers with whom we or ARP have a business relationship. We and ARP may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Unless we and ARP replace our and its natural gas and oil reserves, the reserves and production will decline, which would reduce cash flow from operations and income.

Producing natural gas and oil reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our and ARP’s natural gas and oil reserves and production and, therefore, cash flow and income are highly dependent on our and ARP’s success in efficiently developing and exploiting reserves and economically finding or acquiring additional recoverable reserves. Our and ARP’s ability to find and acquire additional recoverable reserves to replace current and future production at acceptable costs depends on generating sufficient cash flow from operations and other sources of capital, for ARP, principally from the sponsorship of new Drilling Partnerships, all of which are subject to the risks discussed elsewhere in this section.

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

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

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

Both we and ARP may acquire properties with natural gas reserves. Reviews of acquired properties are often incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. A detailed review of records and properties may not necessarily reveal existing or potential problems and may not permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well that we or ARP acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we or ARP inspect a well. Any unidentified problems could result in material liabilities and costs that negatively affect our or ARP’s financial condition and results of operations. Even if we or ARP are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems, the indemnity may not be fully enforceable or the amount of losses that can be recovered may be limited by floors and caps.

 

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Our and ARP’s acquisitions may prove to be worth less than the amount paid, or provide less than anticipated proved reserves, because of uncertainties in evaluating recoverable reserves, well performance, and potential liabilities as well as uncertainties in forecasting oil and natural gas prices and future development, production and marketing costs.

Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, development potential, well performance, future oil and natural gas prices, operating costs and potential environmental and other liabilities. Our and ARP’s estimates of future reserves and estimates of future production for its acquisitions are initially based on detailed information furnished by the sellers and subject to review, analysis and adjustment by its internal staff, typically without consulting independent petroleum engineers. Such assessments are inexact and their accuracy is inherently uncertain, which means that proved reserves estimates may exceed actual acquired proved reserves. We and ARP perform a review of the acquired properties that we believe are generally consistent with industry practices. Nevertheless, such a review may not permit us or ARP to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Neither we nor ARP inspect every well. Even when we or ARP inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. As a result of these factors, the purchase price we or ARP pay to acquire oil and natural gas properties may exceed the value we or ARP realize.

Reviews of the properties included in the acquisitions are inherently incomplete because it is generally not feasible to perform an in-depth review of the individual properties involved in each acquisition given the time constraints imposed by the applicable acquisition agreement. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and potential.

We or ARP may not identify all risks associated with the acquisition of oil and natural gas properties or existing wells, and any indemnification received from sellers may be insufficient to protect us or ARP from such risks, which may result in unexpected liabilities and costs to us or ARP.

We and ARP have acquired and may make additional acquisitions of undeveloped oil and gas properties from time to time, subject to available resources. Any future acquisitions will require an assessment of recoverable reserves, title, future oil and natural gas prices, operating costs, potential environmental hazards, potential tax and other liabilities and other factors. Generally, it is not feasible for us or ARP to review in detail every individual property involved in a potential acquisition. In making acquisitions, we and ARP generally focus most of the title, environmental and valuation efforts on the properties that we or ARP believe to be more significant, or of higher value. Even a detailed review of properties and records may not reveal all existing or potential problems, nor would it permit us or ARP to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Neither we nor ARP inspect in detail every well that we or ARP acquire. Potential problems, such as deficiencies in the mechanical integrity of equipment or environmental conditions that may require significant remedial expenditures, are not necessarily observable even when we or ARP perform a detailed inspection. Any unidentified problems could result in material liabilities and costs that negatively affect our or ARP’s financial condition and results of operations.

Even if we or ARP are able to identify problems with an acquisition, the seller may be unwilling or unable to provide effective contractual protection or indemnity against all or part of these problems, the indemnity may not be fully enforceable, the amount of recoverable losses may be limited by floors and caps, or the financial wherewithal of such seller may significantly limit our ability to recover our costs and expenses. Any limitation on the ability to recover the costs related any potential problem could materially affect our or ARP’s financial condition and results of operations.

 

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Ownership of our and ARP’s oil, gas and NGLs production depends on good title to our and ARP’s respective properties.

Good and clear title to our and ARP’s oil and gas properties is important. Although we and ARP will generally conduct title reviews before the purchase of most oil, gas, NGLs and mineral producing properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat a claim, which could result in a reduction or elimination of the revenue received by us or ARP from such properties.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions or by state environmental agencies.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example:

 

    New York has imposed a de facto moratorium on the issuance of permits for high volume, horizontal hydraulic fracturing until state administered environmental and public health studies are finalized. The Department of Environmental Conservation, or “NYDEC,” accepted comments on its revised proposal to amend state regulations to address high-volume hydraulic fracturing through January 11, 2013, and NYDEC has not issued final regulations. In October 2012, the NYDEC asked the New York Department of Health, or “NYDH,” to assess the health impacts of high volume hydraulic fracturing. The NYDH has not completed its assessment, nor has a deadline been set by which it will complete its review. New York is not expected to take any final action or make any decision regarding hydraulic fracturing until after the health review is completed by NYDH and the NYDEC, through the environmental impact statement, is satisfied that hydraulic fracturing can be done safely in New York State.

 

    Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed. On February 14, 2012, legislation was passed in Pennsylvania requiring, among other things, disclosure of chemicals used in hydraulic fracturing. We refer to this legislation as the “2012 Oil and Gas Act.” To implement the new legislative requirements, on December 14, 2013 the Pennsylvania Department of Environmental Protection, or “PADEP,” proposed amendments to its environmental regulations at 25 PA. Code Chapter 78, Subchapter C, pertaining to environmental protection performance standards for surface activities at oil and gas well sites. According to PADEP, the conceptual changes would update existing requirements regarding containment of regulated substances, waste disposal, site restoration and reporting releases, and would establish new planning, notice, construction, operation, reporting and monitoring standards for surface activities associated with the development of oil and gas wells. PADEP has also proposed to add new requirements for addressing impacts to public resources, identifying and monitoring orphaned and abandoned wells during hydraulic fracturing activities, and submitting water withdrawal information necessary to secure a required water management plan. The public comment period on the proposed amendments to PADEP’s proposed amendments at 25 PA. Code Chapter 78, Subchapter C closed on March 14, 2014, and PADEP is in the process of reviewing and considering over 24,000 comments received during the comment period. Additionally, the PADEP announced in June 2014 that it also intends to propose amendments to its present environmental regulations at 25 PA. Code Chapter 78, Subchapters D (relating to well drilling, operation and plugging) and H (relating to underground gas storage). Lastly, PADEP is in the process of splitting its 25 Pa. Code Chapter 78 regulations, which apply to oil and gas well sites, into two parts as a result of a Pennsylvania General Assembly legislative bill that passed in July 2014 as a companion to Pennsylvania’s budget for 2014 to 2015. 25 Pa. Code Chapter 78 will apply to conventional wells and 25 Pa. Code Chapter 78A will apply to unconventional wells.

 

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    Ohio has in recent years expanded its oil and gas regulatory program. In June 2012, Ohio passed legislation that made several significant amendments to the state’s oil and gas laws, including additional permitting requirements, chemical disclosure requirements, and site investigation requirements for horizontal wells. In June 2013, legislation was adopted imposing sampling requirements and disposal restrictions on certain drilling wastes containing naturally occurring radioactive material and requiring the state regulatory authority to adopt rules on the design and operation of facilities that store, recycle, or dispose of brine or other oil and natural gas related waste materials. In February 2014, the regulatory authority proposed rules imposing detailed construction standards on well pads, and in April 2014, Ohio announced new standard drilling permit conditions to address concerns regarding seismic activity in certain parts of the state.

 

    In September 2012, the Texas Railroad Commission approved new regulations relating to the commercial recycling of produced water and/or hydraulic fracturing flowback fluid. In June 2013, the Texas Railroad Commission adopted new rules regarding well casing, cementing, drilling, completion and well control for ensuring hydraulic fracturing operations do not contaminate nearby water resources.

 

    On April 12, 2013, the West Virginia Legislature passed a legislative rule titled “Rules Governing Horizontal Well Development,” which became effective on July 1, 2013. The rule imposes more stringent regulation of horizontal drilling and was promulgated to provide further direction in the implementation and administration of the Natural Gas Horizontal Well Control Act that became effective on December 14, 2011.

In addition to state law, local land use restrictions, such as municipal ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. Recent changes regarding local land use restrictions in Pennsylvania occurred because of decisions of the Pennsylvania Supreme and Commonwealth Courts. On December 19, 2013, when the Pennsylvania Supreme Court issued its Robinson Township v. Commonwealth of Pennsylvania ruling, which invalidated key sections of the 2012 Oil and Gas Act that placed limits on the regulatory authority of local governments. Additionally, the Pennsylvania Supreme Court remanded a number of issues to the Commonwealth Court for further decision. On July 17, 2014, the Commonwealth Court ruled on the remanded issues. The cumulative effect of the Supreme and Commonwealth Court rulings is that all of the challenged provisions relating to local ordinances contained in the 2012 Oil and Gas Act are invalid, except for the definitions section and most of the updated preemption language in the 2012 Oil and Gas Act that was included from the 1984 Oil and Gas Act. While the total impact of these rulings are not clear and will occur over an extended period of time, an immediate impact of the ruling may be increased regulatory impediments and disputes at the local government level. On June 30, 2014, the New York Court of Appeals issued its opinion in Wallach v. Town of Dryden affirming local zoning laws adopted by two upstate municipalities that prohibited oil and gas-related activities within their borders. Specifically, the Court of Appeals ruled that there was nothing within the plain language, statutory scheme and legislative history of the New York Oil, Gas and Solution Mining Law that manifested an intent by the legislature to preempt a municipality’s home rule authority to regulate land use. If state, local or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling of wells. Generally, Federal, state and local restrictions and requirements are applied consistently to similar types of producers (e.g., conventional, unconventional, etc.), regardless of size of the producing company.

Although, to date, the hydraulic fracturing process has not generally been subject to regulation at the federal level, there are certain governmental reviews either under way or being proposed that focus on environmental aspects of hydraulic fracturing practices, and some federal regulation has taken place. A few of these initiatives are listed here, although others may exist now or be implemented in the future. In April 2012, President Obama established an Interagency Working Group to Support Safe and Responsible Development of Unconventional Domestic Natural Gas Resources with the purpose of coordinating the policies and activities of agencies

 

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regarding unconventional gas development. The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuel as an additive under the Safe Drinking Water Act, or “SDWA.” In May 2012, the EPA issued draft permitting guidance for oil and gas hydraulic fracturing activities using diesel fuel. After reviewing comments submitted on the draft guidance, which were due by August 23, 2012, the EPA submitted its draft guidance to the White House Office of Management and Budget in September 2013. In February 2014, the EPA released its revised final guidance document on SDWA underground injection control permitting for hydraulic fracturing using diesel fuels, along with responses to selected substantive public comments on the EPA’s previous draft guidance, a fact sheet and a memorandum to the EPA’s regional offices regarding implementation of the guidance. The process for implementing the EPA’s final guidance document may vary across the states depending on the regulatory authority responsible for implementing the SDWA Underground Injection Control program in each state. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPA is currently studying the potential environmental effects of hydraulic fracturing on drinking water and groundwater. The EPA issued a progress report regarding the hydraulic fracturing study on December 21, 2012. However, the progress report did not provide any results or conclusions. On December 9, 2013, the EPA’s Hydraulic Fracturing Study Technical Roundtable of subject-matter experts from a variety of stakeholder groups met to discuss the work underway to answer the hydraulic fracturing study’s key research questions. Individual research projects associated with the EPA’s study were recently published in July 2014. Research results are expected to be released in draft form in late 2014 for review by the public and the EPA Science Advisory Board. The EPA has not provided an anticipated date for completion of the report after peer review. In 2013, the EPA indicated that it intended to propose a draft water quality criteria document that would update the aquatic life water quality criteria for chloride by the summer of 2014. However, the EPA has yet to propose the draft water quality criteria document and it has not provided an updated timeframe for the proposal. The EPA announced in its September 2014 “Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans” document that it intends to continue a rulemaking effort to potentially revise the effluent limitation guidelines for the Oil and Gas Extraction Point Source Category to address pretreatment standards for shale gas extraction. The EPA proposed in that same document a detailed study of centralized waste treatment facilities that accept oil and gas extraction wastewater. On May 4, 2012, the U.S. Department of the Interior, Bureau of Land Management proposed a rule that includes provisions requiring disclosure of chemicals used in hydraulic fracturing and construction standards for hydraulic fracturing on federal lands. On May 24, 2013, the Bureau of Land Management published a revised proposed rule to regulate hydraulic fracturing on federal and Indian lands. The comment period closed on August 23, 2013 and the revised proposed rule drew more than 175,000 comments. A final rule is expected to be issued in 2014 or 2015.

Certain members of the U.S. Congress have called upon the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, and Congress has asked the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing. In addition, Congress requested the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. On December 16, 2013, the U.S. Energy Information Administration published an abridged version of its Annual Energy Outlook 2014 with projections to 2040 report, with the full report released on May 7, 2014. These ongoing proposed studies, depending on their degree of pursuit and any meaningful results obtained, could result in initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or one or more other regulatory mechanisms. If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the state and local level, such laws could make it more difficult or costly for us to perform hydraulic fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of natural gas, may preclude our ability to drill wells. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could be significantly affected. Some of the potential effects of changes in Federal, state or local regulation of hydraulic fracturing operations could include, but are not limited to, the following: additional permitting requirements, permitting

 

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delays, increased costs, changes in the way operations, drilling and/or completion must be conducted, increased recordkeeping and reporting, and restrictions on the types of additives that can be used, among other potential effects that are not listed here. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

The third parties on whom we or ARP rely for gathering and transportation services are subject to complex federal, state and other laws that could adversely affect the cost, manner or feasibility of conducting its business.

The operations of the third parties on whom we or ARP rely for gathering and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulation. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we or ARP pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we or ARP rely could have a material adverse effect on our or ARP’s business, financial condition, results of operations and ability to make distributions to unitholders.

Our and ARP’s drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of flowback and produced water. If we or ARP are unable to dispose of the flowback and produced water from the strata at a reasonable cost and within applicable environmental rules, our and ARP’s ability to produce gas economically and in commercial quantities could be impaired.

A significant portion of our and ARP’s natural gas extraction activity utilizes hydraulic fracturing, which results in water that must be treated and disposed of in accordance with applicable regulatory requirements. Environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing may increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse effect on our or ARP’s operations and financial performance. For example, Pennsylvania requires the development, submission and approval of a water management plan before hydraulically fracturing an unconventional well. The requirements of these plans continue to be modified by proposed amendments to state regulations and agency policies and guidance. For Pennsylvania operations located in the Susquehanna River Basin, the Susquehanna River Basin Commission regulates consumptive water uses, water withdrawals, and the diversions of water into and out of the Susquehanna River Basin, and specific approvals are required prior to initiating drilling activities. In June 2012, Ohio passed legislation that established a water withdrawal and consumptive use permit program in the Lake Erie watershed. If certain withdrawal thresholds are triggered due to water needs for a particular project, ARP will be required to develop a Water Conservation Plan and obtain a withdrawal permit for that project.

Our and ARP’s ability to collect and dispose of water will affect production, and potential increases in the cost of water treatment and disposal may affect profitability. The imposition of new environmental initiatives and regulations could include restrictions on our or ARP’s ability to conduct hydraulic fracturing or disposal of produced water, drilling fluids and other substances associated with the exploration, development and production of gas and oil. For example, in July 2012, the Ohio Department of Natural Resources promulgated amendments to the regulations governing disposal wells in Ohio. The rules provide the Department with the authority to require certain testing as part of the process for obtaining a permit for the underground injection of produced water, and require all new disposal wells to be equipped with continuous pressure monitors and automatic shut off devices.

Recently promulgated rules regulating air emissions from oil and natural gas operations could cause us and ARP to incur increased capital expenditures and operating costs.

In August 2012, the EPA published final rules that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source

 

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Performance Standards, which we refer to as the “NSPS,” to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The NSPS require operators, starting in 2015, to reduce volatile organic compound (“VOC”) emissions from oil and natural gas production facilities by conducting “green completions” for hydraulic fracturing, that is, recovering rather than venting the gas and NGLs that come to the surface during completion of the fracturing process. The NSPS also establish specific requirements regarding emissions from compressors, dehydrators, storage tanks, and other production equipment. In addition, effective in 2012, the rules establish new notification requirements before conducting hydraulic fracturing and more stringent leak detection requirements for natural gas processing plants. The NSPS became effective October 15, 2012 and will likely require a number of modifications to our operations, including the installation of new equipment. Compliance with the new rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

States are also proposing more stringent requirements in air permits for well sites and compressor stations. For example, Pennsylvania recently revised its list of sources exempt from air permitting requirements such that previously exempted types of sources associated with oil and gas exploration and production now are required to: (1) obtain an air permit or (2) satisfy specific requirements (emission limits, monitoring and recordkeeping) in order to claim the permit exemption. In conjunction with this proposal, Pennsylvania has finalized revisions to its General Permit for Natural Gas Production Facilities to impose additional and more stringent requirements and emission limits. Ohio is also considering revising its current General Permit for Natural Gas Production Operations to cover emissions from completion activities.

Impact fees and severance taxes could materially increase liabilities.

In an effort to offset budget deficits and fund state programs, many states have imposed impact fees and/or severance taxes on the natural gas industry. In February 2012, Pennsylvania implemented an impact fee for unconventional wells drilled there. An unconventional gas well is a well that is drilled into an unconventional formation, which would include the Marcellus Shale. The impact fee, which changes from year to year, is computed using the prior year’s trailing 12- month NYMEX natural gas price and is based upon a tiered pricing matrix. Based upon natural gas prices for 2013, the impact fee for qualifying unconventional horizontal wells spudded during 2013 was $50,000 per well and the impact fee for unconventional vertical wells was $10,000 per well. The impact fee is due by April 1 of the year following the year that a horizontal unconventional well is spudded or a vertical unconventional well is put into production. The fee will continue for 15 years for a horizontal unconventional well and 10 years for a vertical unconventional well. ARP estimates that the impact fee for its wells including the wells in its Drilling Partnerships will be approximately $1 million for the year ended December 31, 2014.

On May 14, 2014, the Ohio General Assembly passed a substitute version of a bill, H.B.375, introduced on December 4, 2013, that significantly changes Ohio’s severance tax on the production of oil and gas, and the bill is now under consideration by the Ohio Senate. Under the General Assembly’s bill, the tax on the production of oil and gas from conventional wells would be lowered to $0.10/Bbl oil and $0.015/Mcf natural gas, and the tax on the production of oil and gas from unconventional wells would become 2.5% of net proceeds at the wellhead for both oil and gas from the first sale of that oil or gas.

President Obama’s budget proposals for 2014 included proposed provisions with significant tax consequences. If enacted, U.S. tax laws could be amended to eliminate certain deductions for drilling, exploration and development and the mandatory funding of certain public lands and research and development of transportation alternatives.

 

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

How we and ARP plan, design, drill, install, operate and abandon natural gas wells and associated facilities are matters subject to stringent and complex federal, state and local environmental laws and regulations. These include, for example:

 

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

 

    the federal Clean Water Act and comparable state laws and regulations that impose obligations related to spills, releases, streams, wetlands and discharges of pollutants into regulated bodies of water;

 

    the federal Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws that impose requirements for the handling and disposal of waste, including produced waters, from our and ARP’s facilities;

 

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

 

    wildlife protection laws and regulations such as the Migratory Bird Treaty Act that requires operators to cover reserve pits during the cleanup phase of the pit, if the pit is open more than 90 days.

Complying with these requirements is expected to increase costs and prompt delays in natural gas production. There can be no assurance that we or ARP will be able to obtain all necessary permits and, if obtained, that the costs associated with obtaining such permits will not exceed those that previously had been estimated. It is possible that the costs and delays associated with compliance with such requirements could cause us or ARP to delay or abandon the further development of certain properties.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. These enforcement actions may be handled by the EPA and/or the appropriate state agency. In some cases, the EPA has taken a heightened role in oil and gas enforcement activities. For example, in 2011, EPA Region III requested the lead on all oil and gas related violations in the United States Army Corps of Engineers’ Pittsburgh District. The EPA, the United States Army Corps of Engineers and the United States Department of Justice have been actively pursuing instances of unpermitted stream and wetland impacts. We also understand that the EPA has taken an increased interest in assessing operator compliance with the Spill Prevention, Control and Countermeasures regulations, set forth at 40 CFR Part 112.

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

There is an inherent risk that we or ARP may incur environmental costs and liabilities due to the nature of the businesses and the substances handled. For example, an accidental release from one of our or ARP’s wells could subject it or the applicable subsidiary to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for related violations of environmental laws or regulations. Moreover, the

 

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possibility exists that stricter laws, regulations or enforcement policies may be enacted or adopted and could significantly increase our or ARP’s compliance costs and the cost of any remediation that may become necessary. Neither we nor ARP may be able to recover remediation costs under our insurance policies.

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

Our and ARP’s operations are regulated extensively at the federal, state and local levels. The regulatory environment in which we and ARP operate include, in some cases, legal requirements for obtaining environmental assessments, environmental impact studies and/or plans of development before commencing drilling and production activities. In addition, our and ARP’s activities will be subject to the regulations regarding conservation practices and protection of correlative rights. These regulations affect our and ARP’s operations and limit the quantity of natural gas we may produce and sell. A major risk inherent in a drilling plan is the need to obtain drilling permits from state and local authorities. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable conditions or costs could inhibit our ability to develop our respective properties. The natural gas and oil regulatory environment could also change in ways that might substantially increase the financial and managerial costs of compliance with these laws and regulations and, consequently, reduce our profitability. For example, Pennsylvania’s General Assembly approved legislation in February 2012 that imposes significant, costly requirements on the natural gas industry, including the imposition of increased bonding requirements and impact fees for gas wells, based on the price of natural gas and the age of the well. Proposed regulations associated with this legislation have been released for public comment by the Pennsylvania state agencies and, if finalized, will affect how natural gas operations are conducted in Pennsylvania. West Virginia has promulgated regulations associated with its existing Horizontal Well Control Act and is signaling that additional regulations are on the horizon. We and ARP may be put at a competitive disadvantage to larger companies in the industry that can spread these additional costs over a greater number of wells and these increased regulatory hurdles over a larger operating staff.

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 and ARP’s 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 and ARP’s engineers prepare estimates of our proved reserves. Over time, our and ARP’s internal engineers may make material changes to reserve estimates taking into account the results of actual drilling and production. Some of our and ARP’s reserve estimates were made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Also, we and ARP will 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 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. Our and ARP’s PV-10 and standardized measure are calculated using natural gas prices that do not include financial hedges. Numerous changes over time to the assumptions on which our and ARP’s reserve estimates are based, as described above, often result in the actual quantities of natural gas and oil we and ARP ultimately recover being different from the reserve estimates.

 

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

 

    actual prices received for natural gas;

 

    the amount and timing of actual production;

 

    the amount and timing of capital expenditures;

 

    supply of and demand for natural gas; and

 

    changes in governmental regulations or taxation.

The timing of both the production and 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 that we and ARP 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 the company or the natural gas and oil industry in general.

Any significant variance in our or ARP’s assumptions could materially affect the quantity and value of reserves, the amount of PV-10 and standardized measure, and the financial condition and results of operations. In addition, our and ARP’s reserves or PV-10 and standardized measure 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 or ARP’s production can reduce the estimated volumes of reserves because the economic life of the wells could end sooner. Similarly, a decline in market prices for natural gas or oil may reduce our or ARP’s PV-10 and standardized measure.

Risks Relating to ARP’s Drilling Partnerships

ARP or its subsidiaries may be exposed to financial and other liabilities as the managing general partner of the Drilling Partnerships.

ARP or one of its subsidiaries serves as the managing general partner of the Drilling Partnerships and will be the managing general partner of new Drilling Partnerships that it sponsors. As a general partner, ARP or one of its subsidiaries will be contingently liable for the obligations of the partnerships to the extent that partnership assets or insurance proceeds are insufficient. ARP has agreed to indemnify each investor partner in the Drilling Partnerships from any liability that exceeds such partner’s share of the Drilling Partnership’s assets.

ARP may not be able to continue to raise funds through its Drilling Partnerships at desired levels, which may in turn restrict its ability to maintain drilling activity at recent levels.

ARP has sponsored limited and general partnerships to finance certain of its development drilling activities. Accordingly, the amount of development activities that ARP will undertake depends in large part upon its ability to obtain investor subscriptions to invest in these partnerships. ARP has raised $150.0 million, $127.1 million and $141.9 million in calendar years 2013, 2012 and 2011, respectively. In the future, ARP may not be successful in raising funds through these Drilling Partnerships at the same levels, and it also may not be successful in increasing the amount of funds it raises. ARP’s ability to raise funds through its Drilling 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 ARP’s historical track record of generating returns and tax benefits to the investors in its existing partnerships.

In the event that ARP’s Drilling Partnerships do not achieve satisfactory returns on investment or the anticipated tax benefits, ARP may have difficulty in maintaining or increasing the level of Drilling Partnership

 

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fundraising. In this event, ARP may need to seek financing for drilling activities through alternative methods, which may not be available, or which may be available only on a less attractive basis than the financing it realized through these Drilling Partnerships, or it may determine to reduce drilling activity.

Changes in tax laws may impair ARP’s ability to obtain capital funds through Drilling Partnerships.

Under current federal tax laws, there are tax benefits to investing in Drilling Partnerships, including deductions for intangible drilling costs and depletion deductions. Both the Obama Administration’s budget proposal for fiscal year 2014 and other recently introduced legislation included proposals that would, among other things, eliminate or reduce certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include (i) the repeal of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and certain environmental clean-up costs, (iii) the elimination of the deduction for certain domestic production activities, and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted in future years and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. The repeal of these oil and gas tax benefits, if it happens, would result in a substantial decrease in tax benefits associated with an investment in ARP’s Drilling Partnerships. These or other changes to federal tax law may make investment in the Drilling Partnerships less attractive and, thus, reduce ARP’s ability to obtain funding from this significant source of capital funds.

Fee-based revenues may decline if ARP is unsuccessful in sponsoring new Drilling Partnerships.

ARP’s fee-based revenues are based on the number of Drilling Partnerships it sponsors and the number of partnerships and wells it manages or operates. If ARP is unsuccessful in sponsoring future Drilling Partnerships, its fee-based revenues may decline.

ARP’s revenues may decrease if investors in the Drilling Partnerships do not receive a minimum return.

ARP has agreed to subordinate a portion of its share of production revenues, net of corresponding production costs, to specified returns to the investor partners in the Drilling Partnerships, typically 10% to 12% per year for the first five to eight years of distributions. Thus, ARP’s revenues from a particular Drilling Partnership will decrease if the Drilling Partnership does not achieve the specified minimum return. For the years ended December 31, 2013, 2012 and 2011, $9.6 million, $6.3 million and $4.0 million, respectively, of ARP’s revenues, net of corresponding production costs, were subordinated, which reduced ARP’s cash distributions received from the Drilling Partnerships.

Risks Relating to the Separation

We have no operating history as a separate public company, and our historical and pro forma financial information is not necessarily representative of the results that we would have achieved had we been the owner or operator of our assets and may not be a reliable indicator of our future results.

The historical information in this information statement refers to our business as operated by and integrated with Atlas Energy. Our historical and pro forma financial information included in this information statement is derived from the consolidated financial statements and accounting records of Atlas Energy. Therefore, the historical and pro forma financial information included in this information statement does not necessarily reflect the financial condition, results of operations or cash flows that we would have achieved as a separate publicly traded company or as the owner or operator of our assets during the periods presented or those that we will achieve in the future, primarily as a result of the following factors:

 

   

Prior to the separation, our assets were operated by Atlas Energy, rather than as a separate company. Atlas Energy or one of its affiliates performed various corporate functions for us and/or our assets,

 

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including tax administration, cash management, accounting, information services, human resources, ethics and compliance programs, real estate management, investor and public relations, certain governance functions (including internal audit) and external reporting. Our historical financial results and the consolidated pro forma financial results reflect allocations of corporate expenses from Atlas Energy for these and similar functions. These allocations may be less than the comparable expenses we would have incurred had we operated as a separate publicly traded company.

 

    After the completion of the separation, the cost of capital for our business may be higher than Atlas Energy’s cost of capital prior to the separation.

 

    Other significant changes may occur in our cost structure, management, financing and business operations as a result of our operations as a company separate from Atlas Energy managed by our board of directors.

For additional information about the past financial performance of our business and the basis of presentation of the historical combined financial statements and the unaudited pro forma combined financial statements of our business, see the sections entitled “Summary Historical and Unaudited Pro Forma Combined Financial Information,” “Selected Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical financial statements and accompanying notes included elsewhere in this information statement.

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

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

We may have been able to receive better terms from unaffiliated third parties than the terms provided in our agreements with Atlas Energy.

The agreements related to our separation from Atlas Energy, including the separation and distribution agreement, employee matters agreement and other agreements, were negotiated in the context of our separation from Atlas Energy and Atlas Energy’s pending merger with Targa Resources. We were still part of Atlas Energy at this time and, accordingly, these agreements may not reflect terms that would have been reached between unaffiliated parties. The terms of the agreements that were negotiated in the context of our separation relate to, among other things, allocation of assets, liabilities, rights, indemnifications and other obligations between Atlas Energy and us as well as certain ongoing arrangements between Atlas Energy and us. If these agreements had been negotiated with unaffiliated third parties, they might have been more favorable to us. For more information, see the section entitled “Certain Relationships and Related Party Transactions” beginning on page 234.

We may not achieve some or all of the expected benefits of the separation.

We may not be able to achieve the full strategic and financial benefits expected to result from the separation, or such benefits may be delayed or not occur at all. These expected benefits include the following:

 

    The separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and New Atlas, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

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    The separation will create an acquisition currency in the form of units that will enable New Atlas to purchase, and to assist ARP in purchasing, developed and undeveloped resources to accelerate growth of its natural gas and oil production and development business without diluting Atlas Energy unitholders’ participation in growth at Atlas Pipeline Partners, L.P., a publicly traded partnership, the general partner of which is owned by Atlas Energy, or it successors. Current industry trends have created a significant opportunity for New Atlas to grow, and to assist ARP in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

    The separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

    The separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

    The separation will provide enhanced liquidity to holders of Atlas Energy common units, who will hold two separate publicly traded securities that they may seek to retain or monetize.

 

    The separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model, and financial returns.

We may not achieve the anticipated benefits for a variety of reasons, including potential loss of synergies (if any) from operating as one company, potential for increased costs, potential disruptions to the businesses as a result of the separation, potential for the two companies to compete with one another in the marketplace, risks of being unable to achieve the benefits expected to be achieved by the separation, risk that the plan of separation might not be completed, and both the one-time and ongoing costs of the separation. If we fail to achieve some or all of the benefits expected to result from the separation, or if such benefits are delayed, our business, financial conditions and results of operations could be adversely affected.

Atlas Energy may fail to perform under various transaction agreements that will be executed as part of the separation.

In connection with the separation, we and Atlas Energy will enter into a separation and distribution agreement, an employee matters agreement and certain other agreements to effect the separation and distribution and provide a framework for our relationship with Atlas Energy after the separation. These agreements will provide for the allocation between Atlas Energy and us of the employees, assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after our separation from Atlas Energy and will govern the relationship between us and Atlas Energy subsequent to the completion of the separation. We will rely on Atlas Energy to satisfy its performance and payment obligations under these agreements. Following the consummation of the Atlas Merger, Atlas Energy will be a subsidiary of Targa Resources. If Atlas Energy and/or Targa Resources is unable to satisfy Atlas Energy’s obligations under these agreements, including its indemnification obligations, we could incur operational difficulties or losses.

After our separation from Atlas Energy, we will have debt obligations that could restrict our ability to pay cash distributions and have negative impact on our financing options and liquidity position.

As of September 30, 2014, on a pro forma basis after giving effect to the new financing arrangements that New Atlas expects to enter into in connection with the separation and after giving effect to the application of the net proceeds of such financing, New Atlas’s total indebtedness would have been $155.0 million.

This debt could have important consequences to New Atlas and its investors, including:

 

    requiring a substantial portion of New Atlas’s cash flow to make interest payments on this debt;

 

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    making it more difficult to satisfy debt service and other obligations;

 

    increasing the risk of a future credit ratings downgrade of its debt, which could increase future debt costs and limit the future availability of debt financing;

 

    increasing New Atlas’s vulnerability to general adverse economic and industry conditions;

 

    reducing the cash flow available to fund capital expenditures and other corporate purposes and to grow New Atlas’s business;

 

    limiting New Atlas’s flexibility in planning for, or reacting to, changes in its business and the industry;

 

    placing New Atlas at a competitive disadvantage relative to its competitors that may not be as leveraged with debt;

 

    limiting New Atlas’s ability to borrow additional funds as needed or take advantage of business opportunities as they arise; and

 

    limiting New Atlas’s ability to pay cash distributions.

To the extent that New Atlas incurs additional indebtedness, the risks described above could increase. In addition, New Atlas’s actual cash requirements in the future may be greater than expected. New Atlas’s cash flow may not be sufficient to repay all of the outstanding debt as it becomes due, and New Atlas may not be able to borrow money, sell assets or otherwise raise funds on acceptable terms, or at all, to refinance New Atlas’s debt.

The U.S. federal income tax consequences of the separation depend on the status of Atlas Energy as a partnership for U.S. federal income tax purposes on the date of the distribution. If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution, then Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution may be subject to significant tax liability.

The U.S. federal income tax consequences of the distribution depend on the status of Atlas Energy as a partnership for U.S. federal income tax purposes on the date of the distribution. We believe that Atlas Energy should be treated as a partnership for U.S. federal income tax purposes on the date of the distribution, and Atlas Energy files U.S. federal income tax returns on that basis. However, neither we nor Atlas Energy has requested, nor plan to request, a ruling from the IRS on this matter. The IRS could assert that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes. If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes, then Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution may be subject to significant tax liability.

If the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution, Atlas Energy would be subject to tax on gain, if any, that it would have recognized if it had sold our common units received by unitholders of Atlas Energy in the distribution in a taxable sale for their fair market value. In addition, in such case, each unitholder of Atlas Energy who receives our common units in the distribution would be treated as if the unitholder had received a distribution equal to the fair market value of our common units that were distributed to the unitholder, which generally would be treated as either taxable dividend income to the unitholder, to the extent of Atlas Energy’s current or accumulated earnings and profits or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in its units of Atlas Energy, or taxable capital gain, after the unitholder’s tax basis in such units of Atlas Energy is reduced to zero. Accordingly, taxation of Atlas Energy as a corporation on the date of the distribution could result in materially adverse tax consequences to Atlas Energy and unitholders of Atlas Energy who receive our common units in the distribution.

For further information, unitholders should read the section entitled “Certain U.S. Federal Income Tax Matters” beginning on page 260 and consult their own advisors concerning the U.S. federal, state, local and

 

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foreign tax consequences to them of the distribution, including in the event the IRS were successful in asserting that Atlas Energy should be treated as a corporation for U.S. federal income tax purposes on the date of the distribution.

Risks Relating to the Ownership of Our Common Units

We cannot be certain that an active trading market for our common units will develop or be sustained after the distribution and, following the distribution, our unit price may fluctuate significantly. If the unit price declines after the distribution, you could lose a significant part of your investment.

A public market for our common units does not currently exist. We anticipate that prior to the record date for the distribution, trading of shares of our common units will begin on a “when-issued” basis and will continue through the distribution date, but we cannot guarantee that an active trading market will develop or be sustained for our common units after the separation. Nor can we predict the prices at which our common units may trade after the separation, the effect of the separation and distribution on the trading prices of our common units or whether the combined market value of our common units and Atlas Energy’s common units will be less than, equal to or greater than the market value of Atlas Energy common units prior to the separation and distribution.

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

 

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

 

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

 

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

 

    changes in market valuations of similar companies;

 

    departures of key personnel;

 

    commencement of or involvement in litigation;

 

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

 

    variations in the amount of our quarterly cash distributions;

 

    future issuances and sales of our units; and

 

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

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

Sales of our common units following the distribution may cause our unit price to decline.

Sales of substantial amounts of our common units in the public market following the distribution, or the perception that these sales may occur, could cause the market price of our common units to decline. In addition, the sale of these units could impair our ability to raise capital through the sale of additional common units.

Increases in interest rates could adversely affect our unit price.

Credit markets are continuing to experience low interest rates. Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our and ARP’s financing costs to increase accordingly. As with other yield-oriented securities, our unit price is affected by the level of our and ARP’s cash distributions

 

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and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units. A rising interest rate environment could have an adverse impact on our unit price and our and ARP’s ability to issue additional equity or to incur debt to make acquisitions or for other purposes and could affect our and ARP’s ability to make cash distributions at our and ARP’s intended levels.

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash that we have available for distribution depends primarily on our cash flow, including cash reserves and working capital or other borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses, and we may not make cash distributions during periods when we record net income.

There is no guarantee that our unitholders will receive distributions from us.

While our cash distribution policy, consistent with the terms of our limited liability company agreement, will require that we distribute all of our available cash quarterly, our cash distribution policy will be subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

    We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

    Our cash distribution policy will be, and ARP’s cash distribution policy is, subject to restrictions on distributions under any credit facility we enter into and under ARP’s credit facilities, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

    Our board of directors will have the authority under our amended and restated limited liability company agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

 

    Our limited liability company agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

 

    Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

    We can issue additional units, including units that are senior to the common units, without the consent of our unitholders so long as we do not exceed 20% of our common units then outstanding (or senior units convertible into such common units), and these additional units would dilute common unitholders’ ownership interests.

 

    Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations on our cash distribution policy and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

 

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If we do not pay distributions on our common units in any fiscal quarter, our unitholders are not entitled to receive distributions for such prior periods in the future.

Our distributions to our unitholders are not cumulative. Consequently, if we do not pay distributions on our common units with respect to any quarter, our unitholders are not entitled to such payments in the future.

Our cash distribution policy limits our ability to grow.

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

A significant number of our common units may be traded following the distribution, which may cause our unit price to decline.

Any sales of substantial amounts of our common units in the public market or the perception that such sales might occur, in connection with the distribution or otherwise, may cause the market price of our common units to decline. Upon completion of the distribution, we expect that we will have an aggregate of approximately 52.0 million common units issued and outstanding on February 28, 2015. These common units will be freely tradeable without restriction or further registration under the U.S. Securities Act of 1933, as amended, or the “Securities Act,” unless the shares are owned by one of our “affiliates,” as that term is defined in Rule 405 under the Securities Act. We are unable to predict whether large amounts of our common units will be sold in the open market following the distribution. We are also unable to predict whether a sufficient number of buyers would be in the market at that time.

Unitholders may have liability to repay distributions that were wrongfully distributed to them, or other liabilities with respect to ownership of our units.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 18-607 of the Delaware Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Liabilities to members on account of their membership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that for a period of three years from the date of the impermissible distribution, members who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable for the obligations of the transferring member to make contributions to the limited liability company that are known to such purchaser of common units at the time it became a member and for unknown obligations if the liabilities could be determined from the limited liability company agreement.

We may issue additional common units without the consent of our unitholders, which will dilute existing members’ ownership interest in us and may increase the risk that we will not have sufficient available cash to make distributions.

Our limited liability company agreement authorizes us to issue an unlimited number of limited liability company interests of any type without the approval of our unitholders on terms and conditions established by our board of directors at any time subject to certain limitations under existing NYSE listing rules. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

    our unitholders’ proportionate ownership interest in us will decrease;

 

    the amount of cash available for distribution on each unit may decrease;

 

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

 

    the ratio of taxable income to distributions may increase; and

 

    the market price of the common units may decline.

Certain provisions of our limited liability company agreement and Delaware law could deter acquisition proposals and make it difficult for a third party to acquire control of us. This could have a negative effect on the price of our common units.

Our limited liability company agreement contains provisions that are intended to deter coercive takeover practices and inadequate takeover bids and to encourage prospective acquirers to negotiate with our board of directors rather than to attempt a hostile takeover. These provisions include:

 

    a board of directors that is divided into three classes with staggered terms, and this classified board provision could have the effect of making the replacement of incumbent directors more time consuming and difficult;

 

    rules regarding how our common unitholders may present proposals or nominate directors for election;

 

    the inability of our common unitholders to call a special meeting;

 

    the inability of our common unitholders to remove directors; and

 

    the ability of our directors, and not unitholders, to fill vacancies on our board of directors.

These provisions are intended to protect our common unitholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors with more time to assess any acquisition proposal. These provisions are not intended to make us immune from takeovers. However, these provisions will apply even if an offer may be considered beneficial by some of our unitholders and could delay or prevent an acquisition that our board of directors determines is in our best interest and that of our unitholders. These provisions may also prevent or discourage attempts to remove and replace incumbent directors. Any of the foregoing provisions could limit the price that some investors might be willing to pay for our common units.

Our unitholders who fail to furnish certain information requested by our board of directors or who our board of directors determines are not eligible citizens may not be entitled to receive distributions in kind upon our liquidation and their common units will be subject to redemption.

We have the right to redeem all of the units of any holder that is not an eligible citizen if we are or become subject to federal, state, or local laws or regulations that, in the determination of our board of directors, create a substantial risk of cancellation or forfeiture of any property in which we have an interest because of the nationality, citizenship or other related status of any member. Our board of directors may require any member or transferee to furnish information about his nationality, citizenship or related status. If a member fails to furnish information about his nationality, citizenship or other related status within a reasonable period after a request for the information or our board of directors determines after receipt of the information that the member is not an eligible citizen, the member may be treated as a non-citizen assignee. A non-citizen assignee does not have the right to direct the voting of his units and may not receive distributions in kind upon our liquidation. Furthermore, we have the right to redeem all of the common units of any holder that is not an eligible citizen or fails to furnish the requested information.

Common units held by persons who are non-taxpaying assignees will be subject to the possibility of redemption.

If our board of directors determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof

 

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thereof) of one or more of our members, has, or is reasonably likely to have, a material adverse effect on our ability to operate our assets or generate revenues from our assets, then our board of directors may adopt such amendments to our limited liability company agreement as it determines are necessary or appropriate to obtain proof of the U.S. federal income tax status of our members (and their owners, to the extent relevant) and permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rate that can be charged to customers by our subsidiaries or who fails to comply with the procedures instituted by our board of directors to obtain proof of the U.S. federal income tax status.

Tax Risks to Unitholders

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

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

We are currently treated as a partnership for U.S. federal income tax purposes, which requires that 90% or more of our gross income for every taxable year consist of qualifying income, as defined in Section 7704 of the Internal Revenue Code. Qualifying income is defined as income and gains derived from the exploration, development, mining or production, processing, refining, transportation (including pipelines transporting gas, oil, or products thereof), or the marketing of any mineral or natural resource (including fertilizer, geothermal energy and timber). We may not meet this requirement or current law may change so as to cause, in either event, us to be treated as a corporation for U.S. federal income tax purposes or otherwise be subject to U.S. federal income tax. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

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

Current law or our business may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. In addition, because of widespread state budget deficits, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. If any state were to impose a tax upon us as an entity, the cash available for distribution to unitholders would be reduced.

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

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

 

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Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP.

Our ratio of taxable income to cash distributions will be much greater than the ratio applicable to holders of common units in ARP. Other holders of common units in ARP will receive remedial allocations of deductions from ARP. Although we will receive remedial allocations of deductions from ARP, remedial allocations of deductions to us will be very limited. In addition, our ownership of ARP incentive distribution rights will cause more taxable income to be allocated to us from ARP than will be allocated to holders who hold only common units in ARP. If ARP is successful in increasing its distributions over time, our income allocations from our ARP incentive distribution rights will increase, and, therefore, our ratio of taxable income to cash distributions will increase. Because our ratio of taxable income to cash distributions will be greater than the ratio applicable to holders of common units in ARP, our unitholders’ allocable taxable income will be significantly greater than that of a holder of common units in ARP who receives cash distributions from ARP equal to the cash distributions our unitholders would receive from us.

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

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

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

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

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

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform with all aspects of existing U.S. Treasury regulations. A successful IRS challenge to those positions could reduce the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

The sale or exchange of 50% or more of our or ARP’s capital and profits interest within a 12-month period will result in the termination of our or ARP’s partnership for U.S. federal income tax purposes.

We will be considered to have terminated our partnership for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in our capital and profits within a 12-month period.

 

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Likewise, ARP will be considered to have terminated their partnerships for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interest in ARP’s capital and profits within a 12-month period. The termination would, among other things, result in the closing of our or ARP’s taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income for the year in which the termination occurs. Thus, if this occurs, the unitholder will be allocated an increased amount of U.S. federal taxable income for the year in which we are considered to be terminated as a percentage of the cash distributed to the unitholder with respect to that period.

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

If unitholders sell any of their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those units. Prior distributions, and the allocation of losses (including depreciation deductions), to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that unit, will, in effect, become taxable income to them if the unit is sold at a price greater than their tax basis in that unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income to them. The current maximum marginal U.S. federal income tax rate on ordinary income is 39.6% plus a 3.8% Medicare surtax on investment income. As a result, a unitholder may incur a tax liability in excess of the amount of cash it receives from the sale.

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

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

The IRS may challenge our tax treatment related to transfers of units, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. If the IRS were to challenge this method or new U.S. Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

ARP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public unitholders of ARP. The IRS may challenge this treatment, which could adversely affect the value of ARP’s common units and our common units.

When we or ARP issue additional units or engage in certain other transactions, ARP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of its unitholders and us. Although ARP may from time to time consult with professional appraisers

 

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regarding valuation matters, including the valuation of its assets, ARP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its common units as a means to measure the fair market value of its assets. ARP’s methodology may be viewed as understating the value of its assets. In that case, there may be a shift of income, gain, loss and deduction between certain ARP unitholders and us, which may be unfavorable to such ARP unitholders. Moreover, under ARP’s current valuation methods, subsequent purchasers of our common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to their tangible assets and a lesser portion allocated to their intangible assets. The IRS may challenge ARP’s valuation methods, or our or ARP’s allocation of the Section 743(b) adjustment attributable to ARP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ARP’s unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain on the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

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

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

Risks Relating to Our Conflicts of Interest

Although we control ARP and our Development Subsidiary through our ownership of their general partner interests, we owe duties to each such entity and its unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, including between us (as the general partner of ARP), on the one hand, and ARP and its limited partners, on the other hand, as well as between the general partner of our new Development Subsidiary, on the one hand, and our Development Subsidiary and its limited partners, on the other hand. Our directors and officers and the Development Subsidiary’s general partner each have a duty to manage each limited partnership in a manner beneficial to us, its owner. At the same time, these directors and officers have a duty to manage each limited partnership in a manner they believe is beneficial to the partnership’s interests. Our board of directors and the board of directors of our Development Subsidiary’s general partner, or our ARP’s or our Development Subsidiary’s respective conflicts committees, will resolve any such conflict and have broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Conflicts of interest may arise in the following situations, among others:

 

    the allocation of shared overhead expenses;

 

    the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and ARP or our Development Subsidiary, on the other hand;

 

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    the determination and timing of the amount of cash to be distributed to our subsidiaries’ partners and the amount of cash reserved for the future conduct of their businesses;

 

    the decision as to whether the limited partnerships should make acquisitions, and on what terms; and

 

    any decision we make in the future to engage in business activities independent of, or in competition with our subsidiaries.

Certain of our officers and directors may have actual or potential conflicts of interest because of their positions, and their duties may conflict with those of the officers and directors of ARP and our Development Subsidiary’s general partners.

Our officers and directors have duties to manage our business in a manner beneficial to us but since we are also the general partner of ARP, our directors and officers have duties to manage ARP in a manner beneficial to ARP. Certain of our expected executive officers and non-independent directors also serve as executive officers and directors of our Development Subsidiary’s general partner, and, as a result, have duties to manage the Development Subsidiary in a manner beneficial to it. Consequently, these directors and officers may encounter situations in which their obligations to one or more of our subsidiaries, on one hand, and us, on the other hand, are in conflict. The resolution of these conflicts of interest may not always be in our best interest or that of our unitholders. Additionally, some directors and officers may own units, options to purchase units or other equity awards which may be significant for some of these persons. Their positions, and the ownership of such equity of equity awards creates, or may create the appearance of, conflicts of interest when they are faced with decisions that could have different implications for such subsidiaries than the decisions have for us.

Our affiliates and ARP may in certain circumstances compete with us or with each other, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, and this could adversely affect our results of operations and cash available for distribution to our unitholders.

Neither our limited liability company agreement nor the partnership agreement of ARP prohibits ARP or our affiliates from owning assets or engaging in businesses that compete directly or indirectly with us, our affiliates or ARP. In addition, ARP and its affiliates may acquire, develop or dispose of additional assets related to the production and development of oil, natural gas and NGLs or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. As a result, competition among these entities could adversely affect ARP’s or our results of operations and cash available for paying required debt service on our credit facilities or making distributions.

Pursuant to the terms of our limited liability company agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to our directors or executive officers or any of their affiliates. Some of these executive officers and directors also serve as officers of ARP. No such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any unitholder for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. Therefore, ARP and its affiliates may compete with us for investment opportunities and may own an interest in entities that compete with us on an operations basis.

Our limited liability company agreement eliminates our directors’ and officers’ fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our directors and officers.

Our limited liability company agreement contains provisions that eliminate any fiduciary standards to which our directors and officers and their affiliates could otherwise be held by state fiduciary duty laws. Instead, our directors and officers are accountable to us and our unitholders pursuant to the contractual standards set forth in

 

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our limited liability company agreement. Our limited liability company agreement reduces the standards to which our directors and officers would otherwise be held by state fiduciary duty law and contains provisions restricting the remedies available to unitholders for actions taken by our directors or officers or their affiliates. For example, it provides that:

 

    whenever our board of directors or officers make a determination or take, or decline to take, any other action in such capacity, our directors and officers are required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard (including fiduciary standards) imposed by Delaware law or any other law, rule or regulation or at equity;

 

    our directors and officers will not have any liability to us or our unitholders for decisions made in their capacity as a director or officer so long as they acted in good faith, meaning they believed that the decision was not adverse to our interests; and

 

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

It will be presumed that, in making decisions and taking, or declining to take, actions, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any unitholder or the company, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. The existence of all conflicts of interest disclosed in this information statement, and any actions of our directors and officers taken in connection with such conflicts of interest, have been approved by all of our unitholders pursuant to our limited liability company agreement. See “Conflicts of Interest and Duties” beginning on page 243.

By accepting or purchasing a common unit, a unitholder agrees to be bound by the provisions of the limited liability company agreement, including the provisions discussed above and, pursuant to the terms of our limited liability company agreement, is treated as having consented to various actions contemplated in our limited liability company agreement and conflicts of interest that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read “Conflicts of Interest and Duties—No Fiduciary Duties” beginning on page 244.

 

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FORWARD-LOOKING STATEMENTS

This information statement and other materials Atlas Energy and New Atlas have filed or will file with the SEC contains, or will contain forward-looking statements regarding business strategies, market potential, future financial performance and other matters. These statements may be identified by the use of forward-looking terminology such as “anticipate,” “believe,” “budget,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “might,” “plan,” “potential,” “predict” or “should” or the negative thereof or other variations thereon or comparable terminology. In particular, statements about our expectations, beliefs, plans, objectives, assumptions or future events or performance contained in this report are forward-looking statements. We have based these forward-looking statements on our current expectations, assumptions, estimates and projections. While we believe these expectations, assumptions, estimates and projections are reasonable, such forward-looking statements are only predictions and involve known and unknown risks and uncertainties, many of which are beyond our control. These and other important factors may cause our actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. Some of the key factors that could cause actual results to differ from our expectations include:

 

    the risk that Atlas’s unitholders or Targa Resources’ stockholders do not approve the Atlas Merger or that APL’s unitholders do not approve the APL Merger;

 

    termination of the Atlas merger agreement as a result of a competing proposal;

 

    the inability to obtain regulatory approvals required for the Atlas Merger or the APL Merger on the proposed terms and schedule or without conditions that are not anticipated;

 

    the failure of the conditions to the closing of the Atlas Merger or the APL Merger to be satisfied or waived;

 

    potential adverse reactions or changes to business or employee relationships, including those resulting from the announcement or completion of the Atlas Merger or the distribution;

 

    uncertainties as to the timing of the Atlas Merger and the distribution;

 

    competitive responses to the proposed Atlas Merger and/or distribution;

 

    unexpected costs, charges or expenses resulting from the Atlas Merger or the distribution;

 

    litigation relating to the merger;

 

    the outcome of potential litigation or governmental investigations related to the Atlas Merger, the APL Merger or the distribution;

 

    our ability to operate the assets we will acquire in connection with the distribution, and the costs of such operation;

 

    the demand for natural gas, oil, NGLs and condensate;

 

    the price volatility of natural gas, oil, NGLs and condensate;

 

    changes in the market price of our common units;

 

    future financial and operating results;

 

    economic conditions and instability in the financial markets;

 

    resource potential;

 

    realized natural gas and oil prices;

 

    success in efficiently developing and exploiting our and ARP’s reserves and economically finding or acquiring additional recoverable reserves;

 

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    the accuracy of estimated natural gas and oil reserves;

 

    the financial and accounting impact of hedging transactions;

 

    the ability to fulfill the respective substantial capital investment needs of us and ARP;

 

    expectations with regard to acquisition activity, or difficulties encountered in connection with acquisitions;

 

    the limited payment of dividends or distributions, or failure to declare a dividend or distribution, on outstanding common units or other equity securities;

 

    any issuance of additional common units or other equity securities, and any resulting dilution or decline in the market price of any such securities;

 

    restrictive covenants in our and ARP’s indebtedness that may adversely affect operational flexibility;

 

    potential changes in tax laws that may impair the ability to obtain capital funds through investment partnerships;

 

    the ability to raise funds through the investment partnerships or through access to capital markets;

 

    the ability to obtain adequate water to conduct drilling and production operations, and to dispose of the water used in and generated by these operations, at a reasonable cost and within applicable environmental rules;

 

    impact fees and severance taxes;

 

    changes and potential changes in the regulatory and enforcement environment in the areas in which we and ARP conduct business;

 

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

 

    general market, labor and economic conditions and related uncertainties;

 

    the ability to retain certain key customers;

 

    dependence on the gathering and transportation facilities of third parties;

 

    the availability of drilling rigs, equipment and crews;

 

    potential incurrence of significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of hazardous substances into the environment;

 

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

 

    ability to identify all risks associated with the acquisition of oil and natural gas properties, pipeline, facilities or existing wells, and the sufficiency of indemnifications we receive from sellers to protect us from such risks;

 

    expirations of undeveloped leasehold acreage;

 

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

 

    exposure to financial and other liabilities of the managing general partners of the investment partnerships;

 

    the ability to comply with, and the potential costs of compliance with, new and existing federal, state, local and other laws and regulations applicable to our and ARP’s business and operations;

 

    ability to integrate operations and personnel from acquired businesses;

 

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    exposure to new and existing litigations;

 

    the potential failure to retain certain key employees and skilled workers;

 

    development of alternative energy resources; and

 

    the various risks and other factors considered by our board of directors, as described under “The Separation and Distribution—Reasons for the Separation and Distribution” beginning on page 70.

The foregoing list is not exclusive. Other factors that could cause actual results to differ from those implied by the forward-looking statements in this document are more fully described in the “Risk Factors” section of this information statement beginning on page 31. Given these risks and uncertainties, you are cautioned not to place undue reliance on these forward-looking statements. The forward-looking statements included or incorporated by reference in this document speak only as of the date on which the statements were made. We do not undertake and specifically decline any obligation to update any such statements or to publicly announce the results of any revisions to any of these statements to reflect future events or developments except as required by law.

 

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THE SEPARATION AND DISTRIBUTION

Background

On October 13, 2014, Atlas Energy announced that it had entered into the Atlas merger agreement with Targa Resources and a wholly owned subsidiary of Targa Resources providing for such wholly owned subsidiary to merge with and into Atlas Energy, with Atlas Energy surviving as a subsidiary of Targa Resources. Atlas Energy also agreed that pursuant to a separation and distribution agreement substantially in the form attached to the Atlas merger agreement, Atlas Energy would contribute its non-midstream businesses to New Atlas and distribute approximately 52.0 million common units representing a 100% interest in New Atlas to the Atlas Energy unitholders. Atlas Energy has designated Atlas Energy Group, LLC, which is currently the general partner of Atlas Resource Partners, L.P., as the entity with which it will effect these transactions. We refer to Atlas Energy Group, LLC in this information statement as “New Atlas.”

New Atlas is a limited liability company that has elected for U.S. federal income tax purposes to be taxed as a partnership, which Atlas Energy management believed was the most appropriate structure due to the long-lived nature of the assets to be contributed as part of the separation, their expected ability to generate steady cash flows over time, and the potential for tax-efficient growth through future acquisitions, among other considerations. The number of common units to be distributed and the other financial terms of the distribution were determined by management and the board of directors of Atlas Energy’s general partner based on an analysis of the trading price per unit or share of selected comparable companies that were deemed relevant due to their business, structure and market capitalization.

Immediately following completion of the separation and distribution, New Atlas will hold:

 

    the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States;

 

    Atlas Energy’s general and limited partner interests in its exploration and production development subsidiary, which currently conducts operations in the mid-continent region of the United States;

 

    Atlas Energy’s general and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business; and

 

    Atlas Energy’s direct natural gas development and production assets in the Arkoma Basin, which Atlas Energy acquired in July 2013.

Atlas Energy will continue to hold (in addition to its own general partner):

 

    the general partner interest, incentive distribution rights and its common units in Atlas Pipeline Partners, L.P., a publicly traded Delaware master limited partnership and midstream energy service provider engaged in natural gas gathering, processing and treating services.

Pursuant to the terms of the separation and distribution agreement, the distribution of approximately 52.0 million common units in New Atlas, as described in this information statement, is subject to the satisfaction or waiver of certain conditions, including the satisfaction of all conditions to consummating the Atlas Merger (other than the condition that the distribution shall have occurred). We cannot provide any assurances that the distribution will be completed. Furthermore, because the distribution is conditioned on the satisfaction of all conditions to consummating the Atlas Merger, the approval by the holders of a majority of Atlas Energy’s common units of the Atlas merger agreement and the Atlas Merger is a condition to Atlas Energy’s obligation to effect the distribution. Atlas Energy is seeking such approval from the holders of Atlas Energy common units at a special meeting of Atlas Energy’s unitholders to be held on February 20, 2015. We are not asking you to take any other action, make any payment or surrender or exchange any of your common units of Atlas Energy for common units of New Atlas in connection with the distribution.

 

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Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs or will occur. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For a more detailed description of the conditions to the distribution, see the section entitled “The Separation and Distribution—Conditions to the Distribution” beginning on page 74.

Immediately following consummation of the distribution, Atlas Energy and Targa Resources will consummate the Atlas Merger, pursuant to which each common unit of Atlas Energy issued and outstanding immediately prior to the closing of the Atlas Merger will be converted into the right to receive 0.1809 of a share of Targa Resources common stock and $9.12 in cash, without interest. Immediately after the closing of the Atlas Merger, former Atlas Energy unitholders will own approximately     % of the combined company on a fully diluted basis, and existing Targa Resources stockholders will own the remaining approximately     % of the combined company on a fully diluted basis.

Reasons for the Separation and Distribution

The board of directors of Atlas Energy’s general partner believes, in light of its asset make-up and other factors, that separating Atlas Energy into two publicly traded companies is in the best interests of Atlas Energy and its unitholders and has concluded that the separation and distribution will provide each company with certain opportunities and benefits. A wide variety of factors were considered by the board of directors of Atlas Energy’s general partner in evaluating the separation. Among other things, the board of directors considered the following opportunities and benefits:

 

    The separation will enable Atlas Energy unitholders to keep an interest in Atlas Energy’s non-midstream assets following the Atlas Merger with Targa Resources.

 

    The separation will facilitate deeper understanding by investors of the different businesses of Atlas Energy and New Atlas, allowing investors to more transparently value the merits, performance and future prospects of each company, which could increase overall unitholder value.

 

    The separation will create an acquisition currency in the form of units that will enable New Atlas to purchase, and to assist ARP and the Development Subsidiary in purchasing, developed and undeveloped resources to accelerate growth of its natural gas and oil production and development business without diluting Atlas Energy unitholders’ participation in growth at Atlas Pipeline Partners, L.P., a publicly traded partnership the general partner of which is owned by Atlas Energy, and following the APL Merger, growth in Targa Resources Partners. Current industry trends have created a significant opportunity for New Atlas to grow, and to assist ARP and the Development Subsidiary in growing, through the acquisition of assets being sold to close the funding gap created by the success of low-risk unconventional resources.

 

    The separation will allow each business to more effectively pursue its own distinct operating priorities and strategies, and will enable the management of both companies to pursue unique opportunities for long-term growth and profitability.

 

    The separation will create independent equity structures that will afford each company direct access to capital markets and facilitate the ability to capitalize on its unique growth opportunities.

 

    The separation will provide enhanced liquidity to holders of Atlas Energy common units, who will hold two separate publicly traded securities that they may seek to retain or monetize.

 

    The separation will provide investors with two distinct and targeted investment opportunities with different investment and business characteristics, including opportunities for growth, capital structure, business model and financial returns.

 

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Neither we nor Atlas Energy or any of their affiliates can assure you that, following the separation and distribution, any of the benefits described above or otherwise will be realized to the extent anticipated or at all. The board of directors of Atlas Energy’s general partner also considered a number of potentially negative factors in evaluating the separation, including potential loss of synergies (if any) from operating as one company, potential for increased costs, potential disruptions to the businesses as a result of the separation, potential for the two companies to compete with one another in the marketplace, risks of being unable to achieve the benefits expected to be achieved by the separation, risk that the plan of separation might not be completed and both the one-time and ongoing costs of the separation. The board of directors of Atlas Energy’s general partner concluded that notwithstanding these potentially negative factors, separation would be in the best interests of Atlas Energy and its unitholders.

In view of the wide variety of factors considered in connection with the evaluation of the separation and the complexity of these matters, the board of directors of Atlas Energy’s general partner did not find it useful to, and did not attempt to, quantify, rank or otherwise assign relative weights to the factors considered. The individual members of the board of directors of Atlas Energy’s general partner may have given different weights to each of the factors.

In addition, completion of the distribution is a condition to the Atlas Merger, and indirectly the APL Merger. For more information on the Atlas Merger, see the Proxy Statement.

Contribution of Assets Prior to the Distribution

We were formed as a limited liability company in Delaware in October 2011 to serve as the general partner of Atlas Resource Partners, L.P. In connection with the separation, Atlas Energy will contribute to us all of Atlas Energy’s businesses and assets other than those related to its “Atlas Pipeline Partners” segment. As a result of this contribution, we will hold, directly or indirectly, the general partner interest, incentive distribution rights and Atlas Energy’s limited partner interest in Atlas Resource Partners, L.P., a publicly traded Delaware master limited partnership and an independent developer and producer of natural gas, crude oil and NGLs with operations in basins across the United States, Atlas Energy’s general and limited partner interests in its exploration and production Development Subsidiary, which currently conducts operations in the mid-continent region of the United States, its general partner and limited partner interests in Lightfoot Capital Partners, a limited partnership investment business, and its other natural gas and oil exploration and production assets. As part of the plan to separate such businesses from such segment, Atlas Energy plans to transfer to us its equity interests in Atlas Resource Partners as well as the general partner and limited partner interests of the Development Subsidiary and certain entities that operate its other natural gas and oil exploration and production business and hold its general and limited partner interests in Lightfoot Capital Partners.

When and How You Will Receive Common Units in the Distribution

We expect that Atlas Energy will distribute approximately 52.0 million of our common units (other than common units sold as a result of fractional units) on February 28, 2015, the distribution date. The distribution will be made to all holders of record of Atlas Energy common units on February 25, 2015, the record date for the distribution. We expect that the distribution date and the closing date for the Atlas Merger will be the same day. Atlas Energy’s transfer agent and registrar, Broadridge Corporate Issuer Solutions, Inc., also referred to as “Broadridge,” will serve as transfer agent and registrar for the New Atlas common units and as distribution agent in connection with the distribution of New Atlas common units.

If you own Atlas Energy common units of the close of business on the record date, the New Atlas common units that you are entitled to receive in the distribution will be issued electronically, as of the distribution date, to your account as follows:

 

   

Registered Unitholders. If you own your Atlas Energy common units directly (either in book-entry form through an account at Atlas Energy’s transfer agent, Broadridge, and/or if you hold physical paper

 

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stock certificates), you will receive your New Atlas common units by way of direct registration in book-entry form. Registration in book-entry form refers to a method of recording unit ownership when no physical paper share certificates are issued to unitholders, as is the case in this distribution.

Commencing on or shortly after the distribution date, the distribution agent will mail to you an account statement that indicates the number of New Atlas common units that have been registered in book-entry form in your name. If you have any questions concerning the mechanics of having your ownership of our common units registered in book-entry form, we encourage you to contact Broadridge at the address set forth in this information statement.

 

    Beneficial Unitholders. Most Atlas Energy unitholders hold their Atlas Energy units beneficially through a bank or brokerage firm. In such cases, the bank or brokerage firm would be said to hold the units in “street name” and ownership would be recorded on the bank or brokerage firm’s books. If you hold your Atlas Energy common units through a bank or brokerage firm, your bank or brokerage firm will credit your account for the New Atlas common units that you are entitled to receive in the distribution. If you have any questions concerning the mechanics of having your common units held in “street name,” we encourage you to contact your bank or brokerage firm.

Transferability of Our Common Units

Our common units that will be distributed in the distribution will be transferable without registration under the Securities Act, except for common units received by persons who may be deemed to be our affiliates. Persons who may be deemed to be our affiliates after the distribution generally include individuals or entities that control, are controlled by or are under common control with us, which may include certain of our executive officers, directors or principal unitholders. Securities held by our affiliates will be subject to resale restrictions under the Securities Act. Our affiliates will be permitted to sell our common units only pursuant to an effective registration statement or an exemption from the registration requirements of the Securities Act, such as the exemption afforded by Rule 144 under the Securities Act.

Number of Our Common Units that You Will Receive

For each common unit of Atlas Energy that you own at the close of business on February 25, 2015, the record date, you will receive one of our common units. No fractional common unit will be distributed. Instead, if you are a registered holder, the transfer agent will aggregate fractional units into whole units, sell the whole units in the open market at prevailing market prices and distribute the aggregate cash proceeds (net of discounts and commissions) of the sales pro rata (based on the fractional unit that such holder would otherwise be entitled to receive) to each holder who otherwise would have been entitled to receive a fractional unit in the distribution. The transfer agent, in its sole discretion, without any influence by Atlas Energy or us, will determine when, how, through which broker-dealer and at what price to sell the whole unit. Any broker-dealer used by the transfer agent will not be an affiliate of either Atlas Energy or us. Neither we nor Atlas Energy will be able to guarantee any minimum sale price in connection with the sale of these shares. Recipients of cash in lieu of fractional shares will not be entitled to any interest on the amounts of payment made in lieu of fractional shares.

The receipt of cash in lieu of fractional shares of our common units may be taxable to you for U.S. federal income tax purposes. See “Certain U.S. Federal Income Tax Matters” beginning on page 260 for a summary of the material U.S. federal income tax consequences of the distribution. We estimate that it will take approximately two weeks from the distribution date for the distribution agent to complete the distributions of the aggregate net cash proceeds. If you hold your Atlas Energy common units through a bank or brokerage firm, your bank or brokerage firm will receive, on your behalf, your pro rata share of the aggregate net cash proceeds of the sales and will electronically credit your account for your share of such proceeds.

 

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Treatment of Equity Based Compensation

As of the distribution date, each Atlas Energy phantom unit and unit option will be adjusted, as described in Compensation Discussion and Analysis—Elements of Atlas Energy’s Compensation Program—Going Forward.

Incurrence of Debt

In connection with the distribution, New Atlas expects to incur approximately $155 million of debt pursuant to a term loan facility. The net proceeds of such debt are expected to fund a cash transfer of $150 million to Atlas Energy, as described in “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers.”

Results of the Distribution

After our separation from Atlas Energy and the distribution, we will be a separate, publicly traded company. Immediately after the distribution, Atlas Energy will no longer hold any of our common units. As a result, following the separation and distribution, the New Atlas unitholders will elect our board of directors. Immediately following the distribution, we expect to have approximately 170 unitholders of record, based on the number of registered holders of Atlas Energy common units as of January 29, 2015 and approximately 52.0 million New Atlas common units outstanding. The actual number of common units to be distributed will be determined at the close of business on February 25, 2015, the record date for the distribution, and will reflect any exercise of Atlas Energy options between the date that the board of directors of Atlas Energy’s general partner declares the distribution and the record date for the distribution. The distribution will not affect the number of outstanding Atlas Energy common units or any rights of Atlas Energy unitholders. Atlas Energy will not distribute any fractional shares of our common units.

Before the separation, we will enter into a separation and distribution agreement, an employee matters agreement, an operating agreement for certain Atlas Energy assets in Tennessee and other agreements with Atlas Energy to effect the separation and provide a framework for the relationships between us and Atlas Energy after the separation. These agreements will provide for the allocation between Atlas Energy and New Atlas of Atlas Energy’s assets, liabilities and obligations (including investments, property and employee benefits and tax-related assets and liabilities) of Atlas Energy attributable to periods before, at and after our separation from Atlas Energy and will govern the relationship between us and Atlas Energy subsequent to the completion of the separation. Following the Atlas Merger, Atlas Energy will be a wholly owned subsidiary of Targa Resources. For a more detailed description of these agreements, see “Certain Relationships and Related Party Transactions” beginning on page 234.

Effect on Atlas Energy Common Units

The number of outstanding common units of Atlas Energy will not change as a result of the distribution. As a result of the Atlas Merger, which will occur immediately following the distribution, you will receive 0.1809 of a share of Targa Resources common stock and $9.12 in cash, without interest, for each Atlas Energy common unit you own. Immediately after the closing of the Atlas Merger, Atlas Energy unitholders will own approximately 18% of the combined company on a fully diluted basis, and Targa Resources shareholders will own the remaining approximately 82% of the combined company on a fully diluted basis. For more information on when and how you will receive Targa Resources common shares in the Atlas Merger, please refer to the Proxy Statement.

Market for Our Common Units

There is currently no public market for our common units. A condition to the distribution is authorization of the listing of our common units on the NYSE, subject to official notice of issuance. We have applied to list our common units on the NYSE under the symbol “ATLS.” We have not and will not set the initial price of our common units. The initial price will be established by the public markets.

 

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We cannot predict the price at which our common units will trade after the distribution. In fact, the sum of (1) the trading price of our common units that each Atlas Energy unitholder will receive in the distribution and (2) the merger consideration received by such unitholder from Targa Resources may not equal the “regular-way” trading price of an Atlas Energy common unit immediately prior to the distribution. The price at which our common unit trades may fluctuate significantly, particularly until an orderly public market develops. Trading prices for our common units will be determined in the public markets and may be influenced by many factors. See “Risk Factors—Risks Relating to the Ownership of Our Common Units—Sales of our common units following the distribution may cause our unit price to decline” on page 56.

Trading Prior to the Distribution Date

Beginning shortly before the record date, we expect that there will be two markets in Atlas Energy common units: a “regular-way” market and an “ex-distribution” market. Atlas Energy common units that trade on the “regular-way” market will trade with an entitlement to our common units that will be distributed pursuant to the distribution. Atlas Energy common units that trade on the “ex-distribution” market will trade without an entitlement to our common units that will be distributed pursuant to the distribution. Therefore, if you sell Atlas Energy common units in the “regular-way” market up to and including the distribution date, you will be selling your right to receive our common units in the distribution. If you sell Atlas Energy common units on the “ex-distribution” market up to and including through the distribution date, you will receive our common units that you would be entitled to receive pursuant to your ownership as of the record date of the Atlas Energy common units.

Furthermore, beginning shortly before the record date and continuing up to and including through the distribution date, we expect that there will be a “when-issued” market in our common units. “When-issued” trading refers to a sale or purchase made conditionally because the security has been authorized but not yet issued. The “when-issued” trading market will be a market for our common units that will be distributed to Atlas Energy unitholders on the distribution date. If you owned Atlas Energy common units at the close of business on the record date, you would be entitled to receive a certain number of our common units distributed pursuant to the distribution. You may trade this entitlement to our common units, without the Atlas Energy common units that you own, on the “when-issued” market. On the first trading day following the distribution date, “when-issued” trading with respect to our common units will end, and “regular-way” trading will begin.

Conditions to the Distribution

We expect that the distribution will be effective on February 28, 2015, the distribution date, provided that, among other conditions described in this information statement, the following conditions shall have been satisfied or waived by the general partner of Atlas Energy, subject to the restrictions set forth below:

 

    the SEC shall have declared effective our registration statement on Form 10, of which this information statement is a part, and no stop order relating to the registration statement is in effect;

 

    the transfer of assets and liabilities from Atlas Energy to New Atlas shall have been completed in accordance with the separation and distribution agreement;

 

    any required actions and filings with regard to state securities and blue sky laws of the United States (and any comparable laws under any foreign jurisdictions) shall have been taken and, where applicable, have become effective or been accepted;

 

    the transaction agreements relating to the separation shall have been duly executed and delivered by the parties thereto;

 

    no order, injunction or decree issued by any court or agency of competent jurisdiction or other legal restraint or prohibition preventing consummation of the separation, distribution or any of the transactions contemplated by the separation and distribution agreement or any ancillary agreement, shall be in effect;

 

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    our common units to be distributed shall have been accepted for listing on the NYSE, subject to official notice of issuance;

 

    Atlas Energy shall retain at least $5,000,000 of cash, and its net working capital (including retained cash) as of the distribution shall be no less than $5,000,000;

 

    Atlas Energy shall have received, or shall receive simultaneously with the distribution, certain payments from Targa Resources under the Atlas merger agreement and the proceeds from the cash transfers from New Atlas, as described in “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers”; and

 

    the conditions required for consummating the Atlas Merger, as set forth in the Proxy Statement relating to that transaction, shall have been satisfied or waived (other than the condition that the distribution shall have occurred).

Atlas Energy also entered into the APL merger agreement with APL, Atlas Pipeline Partners GP, Targa Resources, Targa Resources Partners, Targa Resources Partners’ general partner and a newly formed subsidiary of Targa Resources Partners providing for the APL Merger to occur. The Atlas Merger and the APL Merger are each conditioned on the other and will each occur only if the other occurs. As a result, the distribution is indirectly conditioned on the satisfaction of the conditions required for consummating the APL Merger. For additional information about the merger of APL and Targa Resources Partners, please read Atlas Energy’s separate proxy statement/prospectus relating to the Atlas Merger.

Subject to the terms and conditions of the Atlas merger agreement, the separation and distribution agreement may not be terminated prior to the distribution without the mutual consent of Atlas Energy and Targa Resources. Neither Atlas Energy nor New Atlas will be permitted to amend, waive, supplement or modify any provision of the separation and distribution agreement, or make any determination as to the satisfaction or waiver of the conditions to the distribution, in a manner that is materially adverse to Atlas Energy, Targa Resources or their affiliates or that would prevent or materially impede consummation of the Atlas Merger without first obtaining Targa Resources’ consent.

So long as it first obtains Targa Resources’ consent, Atlas Energy will have the discretion to determine (and change) the terms of, and whether to proceed with, the distribution. To the extent it determines to so proceed, Atlas Energy will have the sole and absolute discretion to determine the record date for the distribution and the distribution date and distribution ratio. The fulfillment of the foregoing conditions does not create any obligations on the part of Atlas Energy to its unitholders to effect the distribution or in any way limit Atlas Energy’s right to terminate the separation or distribution agreement or alter the consequences of any such termination from those specified in the agreement. Any determination made by the board of Atlas Energy’s general partner prior to the distribution concerning the satisfaction or waiver of any or all of the conditions to the distribution shall be conclusive and binding on Atlas Energy and New Atlas. Atlas Energy does not intend to notify its unitholders of any modifications to the terms of the separation and distribution that, in the judgment of the board of directors of its general partner, are not material. For example, the board of directors of Atlas Energy’s general partner might consider to be material such matters as significant changes to the distribution ratios, the assets to be contributed or the liabilities to be assumed in the separation. To the extent that the board of directors of Atlas Energy’s general partner determines that any modifications by Atlas Energy changes the material terms of the distribution, Atlas Energy will notify its unitholders in a manner reasonably calculated to inform them about the modification as may be required by law, by, for example, publishing a press release, filing a current report on Form 8-K, or circulating a supplement to the information statement.

 

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CASH DISTRIBUTION POLICY

Set forth below is a summary of the significant provisions of our limited liability company agreement and ARP’s limited partnership agreement that relate to our and ARP’s cash distributions and a forecast of our quarterly cash distribution rate. You should read the following discussion of our cash distribution policy in conjunction with the more detailed information regarding the factors and assumptions upon which our cash distribution policy is based in “—Significant Forecast Assumptions” and “—Sensitivity Analysis” below. In addition, you should read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and material risks inherent in our and ARP’s business.

For additional information regarding our historical and pro forma operating results, you should refer to our audited historical financial statements for the years ended December 31, 2013, 2012 and 2011, our unaudited historical financial statements for the nine months ended September 30, 2014 and 2013, and our pro forma financial statements for the nine months ended September 30, 2014 and the year ended December 31, 2013, each included elsewhere in this information statement.

General

Rationale for Our Cash Distribution Policy

The amount of distributions paid under our cash distribution policy and the decision to make any distribution will be determined by our board of directors in its discretion, taking into account the terms of our limited liability company agreement. Our cash distribution policy reflects a basic judgment, given our current asset base, that our unitholders will be better served by the distribution of our available cash (which is defined in our limited liability company agreement and is net of any expenses and reserves established by our board of directors) than by our retaining such available cash. It is the current policy of our board of directors that we should increase our level of cash distributions per unit only when, in its judgment, it believes that:

 

    we have sufficient reserves and liquidity for the proper conduct of our business; and

 

    we can maintain such an increased distribution level for a sustained period.

The amount of “available cash,” which is defined in our limited liability company agreement, will be determined by our board of directors after the completion of the distribution and will be based upon recommendations from our management. Because we believe that we will generally finance any expansion capital expenditures and investment capital expenditures from external financing sources, we believe that our investors are best served by our distributing all of our available cash. In addition, because we are not subject to entity-level U.S. federal income tax as a partnership, we have more cash to distribute to you than would be the case if we were subject to U.S. federal income tax. Our cash distribution policy is consistent with the terms of our limited liability company agreement, which requires that we distribute all of our available cash.

The board of directors intends to adopt a cash distribution policy that will require, pursuant to our amended and restated limited liability company agreement, that we distribute all of our available cash quarterly to our unitholders within 50 days following the end of each calendar quarter in accordance with their respective percentage interests. Our cash distribution policy will be consistent with the terms of our limited liability company agreement. Under our limited liability company agreement, available cash will be defined to mean generally, for each fiscal quarter, all cash on hand at the date of determination of available cash in respect of such quarter, less the amount of cash reserves established by our board of directors, which will not be subject to a cap, to:

 

    comply with applicable law;

 

    comply with any agreement binding upon us or our subsidiaries (exclusive of ARP and Lightfoot and their respective subsidiaries);

 

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    provide for future capital expenditures, debt service and other credit needs as well as any federal, state, provincial or other income tax that may affect us in the future; or

 

    otherwise provide for the proper conduct of our business.

These reserves will not be restricted by magnitude, but only by type of future cash requirements with which they can be associated. Our available cash will also include cash on hand resulting from borrowings made after the end of the quarter. When our board of directors determines our quarterly distributions, it will consider current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Our distributions to limited partners will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, our unitholders will not be entitled to receive such payments in the future.

Restrictions and Limitations on Our Cash Distribution Policy

While our cash distribution policy, consistent with the terms of our limited liability company agreement, will require that we distribute all of our available cash quarterly, our cash distribution policy will be subject to the following restrictions and limitations and may be changed at any time, including in the following ways:

 

    We may lack sufficient cash to pay distributions to our unitholders due to a number of factors, including increases in our general and administrative expenses, principal or interest payments on our future outstanding debt, elimination of future distributions from ARP, the effect of working capital requirements and anticipated cash needs of us or ARP.

 

    Our cash distribution policy will be, and ARP’s cash distribution policy is, subject to restrictions on distributions under any credit facility we enter into and under ARP’s credit facilities, respectively, such as material financial tests and covenants and limitations on paying distributions during an event of default.

 

    Our board of directors will have the authority under our amended and restated limited liability company agreement to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders. The establishment of those reserves could result in a reduction in future cash distributions to our unitholders pursuant to our stated cash distribution policy.

 

    Our limited liability company agreement, including the cash distribution policy contained therein, may be amended by a vote of the holders of a majority of our common units.

 

    Even if our cash distribution policy is not amended, modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our board of directors, taking into consideration the terms of our limited liability company agreement.

 

    We can issue additional units, including units that are senior to the common units, without the consent of our unitholders, subject to existing NYSE listing rules, and these additional units would dilute common unitholders’ ownership interests.

 

    Under Section 18-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Because of these restrictions and limitations and our ability to change our cash distribution policy, we may not have available cash to distribute to our unitholders, and there is no guarantee that our unitholders will receive quarterly distributions from us.

Our Cash Distribution Policy Will Limit Our Ability to Grow

Because we will distribute our available cash rather than reinvesting it in our business, our growth may not be as significant as businesses that reinvest their available cash to expand ongoing operations. Because our primary cash-generating assets currently consist of our partnership interests in ARP, including incentive

 

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distribution rights, our growth initially will be dependent upon ARP’s ability to increase its quarterly distribution per unit. If we issue additional common units or incur debt to fund acquisitions, and expansion and investment capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our limited liability company agreement on our ability to issue additional units, including units ranking senior to the common units, although existing NYSE listing rules requires unitholder approval for us to issue common units in excess of 20% of our common units then outstanding (or senior units convertible into such common units).

ARP’s Ability to Grow is Dependent on its Ability to Access External Growth Capital

Consistent with the terms of its partnership agreement, ARP has distributed to its partners most of the cash generated by its operations. This has required it to rely upon external financing sources, such as commercial borrowings and other debt and equity issuances, to fund its acquisition and growth capital expenditures. If ARP is unable to finance growth externally, its cash distribution policy will significantly impair its ability to grow. If ARP issues additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that ARP will be unable to maintain or increase its per unit distribution level, which in turn may affect the available cash that we have to distribute to our unitholders. The incurrence of additional commercial or other debt to finance ARP’s growth strategy would result in increased interest expense to ARP, which in turn may affect the available cash that we have to distribute to our unitholders.

Distributions of Cash Upon Liquidation

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

Adjustments to Capital Accounts

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

Our Initial Quarterly Distribution Rate

New Atlas believes, based on the assumptions and considerations discussed in the section entitled “Cash Distribution Policy—Estimated Initial Cash Available for Distribution” beginning on page 79, that upon completion of the distribution of the New Atlas common units, New Atlas’s initial quarterly distribution will, subject to proration as described below, be equal to $0.275 per common unit, or $1.10 per common unit on an annualized basis. This equates to an aggregate cash distribution of approximately $14.4 million per quarter, or approximately $57.8 million per year. New Atlas’s ability to make cash distributions at the initial distribution rate will be subject to the factors described in the section entitled “Cash Distribution Policy—General— Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77. We cannot assure you that any distributions will be declared or paid by us, and there is no guarantee of distributions at a particular level or

 

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of any distributions being made. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. For more information, see the section entitled “Cash Distribution Policy—General—Restrictions and Limitations on Our Cash Distribution Policy” beginning on page 77.

We expect to pay a prorated cash distribution for the first quarter that we are a publicly traded company. This prorated cash distribution will be paid for the period beginning on the distribution date for the New Atlas common units and ending on the last day of that fiscal quarter. Any cash distributions received by New Atlas from Atlas Resource Partners related to the period beginning on the date of the most recent cash distribution to the Atlas Energy unitholders prior to the distribution date for the New Atlas common units and ending on such distribution date will be included in this prorated cash distribution.

The following table sets forth the estimated aggregate distribution amounts payable on our common units during the year following the completion of the distribution of the New Atlas common units at our initial distribution rate of $0.275 per common unit (or $1.10 per common unit on an annualized basis).

 

            Initial Quarterly Distribution  
     Number of Units      One Quarter      Four Quarters  

Common units

     52,500,000       $ 14,437,500       $ 57,750,000   

Our cash distributions will not be cumulative. Consequently, if distributions on our common units are not paid with respect to any fiscal quarter, including those at the anticipated initial quarterly distribution rate, our common unitholders will not be entitled to receive that quarter’s payments in the future.

Overview of Presentation

In the sections that follow, we present the basis for our belief that we will be able to pay our initial quarterly distribution of $0.275 per common unit for each quarter during the year ending December 31, 2015. In those sections, we present:

 

    Our “Estimated Initial Cash Available for Distribution” in which we present our estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay distributions at the initial quarterly distribution rate on all the outstanding common units for each quarter for the year ending December 31, 2015.

 

    Our “Unaudited Pro Forma Cash Available for Distribution,” in which we present the amount of pro forma available cash we would have had available for distribution to our unitholders in the twelve months ended September 30, 2014 and December 31, 2013, based on our pro forma financial statements included elsewhere in this information statement. Our calculation of pro forma available cash in this table should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed in an earlier period.

Estimated Initial Cash Available for Distribution

We forecast that our estimated initial cash available for distribution for the year ending December 31, 2015 will be approximately $62.2 million. This amount would exceed the amount of cash available for distribution we must generate to support the payment of the initial quarterly distributions for four quarters on our common units outstanding immediately after the distribution date by $2.8 million for the year ending December 31, 2015. The number of outstanding units on which we have based our estimate does not include any common units that may be issued under the long-term incentive plan that we will adopt prior to the closing of the distribution.

 

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We do not as a matter of course make public projections of financial information. Our forecast information below presents, to our best knowledge and belief, our expected results of operations and cash flows for the year ending December 31, 2015. Our forecast financial information reflects our judgment as of the date of this information statement of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2015. Please read below under the section entitled “Cash Distribution Policy—Significant Forecast Assumptions” for further information as to the significant assumptions we have made for the financial forecast. There will likely be differences between our forecast and actual results, and those differences could be material.

Our forecast financial information is a forward-looking statement and should be read together with the historical and pro forma financial statements and the accompanying notes included elsewhere in this information statement and together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 113. This forecast was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the assumptions on which we base our belief that we can generate sufficient distributable cash flow on an annual basis to pay the full initial quarterly distributions on our common units for the year ending December 31, 2015. We did not use quarterly estimates in concluding that there would be sufficient distributable cash flow to pay the initial quarterly distributions on our common units for the year ending December 31, 2015. Historically, our distributable cash flow has varied significantly on a quarterly basis as a result of seasonal changes and other factors. For more information regarding these factors, please read “Risk Factors—Risks Relating to Our Business.” As a result of the quarterly seasonal and other variations in our distributable cash flow and the inherent difficulty in projecting the precise timing of revenue and expenses, we believe that any estimate of our quarterly distributable cash flow would involve a high degree of potential inaccuracy. To the extent that there is a shortfall of quarterly distributable cash flow compared with the initial quarterly distributions on our common units during the year ending December 31, 2015, we believe we will be able to utilize cash on hand or borrowings under any credit facility we enter into to fund the shortfall, with such amounts replenished in subsequent quarters.

The prospective financial information included in this information statement has been prepared by, and is the responsibility of, our management. Grant Thornton LLP has neither compiled nor performed any procedures with respect to the accompanying prospective financial information and, accordingly, Grant Thornton LLP does not express an opinion or any other form of assurance with respect thereto. The Grant Thornton LLP report included in this information statement relates to our historical financial information. It does not extend to the prospective financial information and should not be read to do so.

When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under “Risk Factors.” Any of the risks discussed in this information statement, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated distributable cash flow.

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

 

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New Atlas

Estimated Cash Available for Distribution(1)

 

     Year Ending
December 31,
2015
 

Atlas Resource Partners, L.P.

  

Revenues:

  

Gas and oil production

   $ 539,500   

Well construction and completion

     307,400   

Administration and oversight

     22,100   

Well services

     27,400   

Gathering and processing

     8,600   

Other

     100   
  

 

 

 

Total revenues

  905,100   
  

 

 

 

Costs and Expenses:

Gas and oil production

  203,800   

Well construction and completion

  267,300   

Well services

  10,400   

Gathering and processing

  10,400   

General and administrative expense

  45,900   

Depreciation, depletion and amortization

  233,200   
  

 

 

 

Total costs and expenses

  771,000   
  

 

 

 

Operating income

  134,100   

Interest expense

  (82,125
  

 

 

 

Net income

  51,975   

Preferred limited partner dividends

  (19,000
  

 

 

 

Net income attributable to common limited partners and the general partner

$ 32,975   
  

 

 

 

Plus:

Preferred limited partner dividends

  19,000   

Interest expense

  82,125   

Depreciation, depletion and amortization

  233,200   
  

 

 

 

EBITDA

  367,300   

Plus: Non-cash stock compensation expense

  18,000   
  

 

 

 

Adjusted EBITDA

  385,300   

Less: Interest expense

  (82,125

Less: Preferred limited partner dividends

  (19,000

Plus: Amortization of deferred finance costs

  12,075   

Less: Expansion capital expenditures

  139,700   

Plus: Financing for expansion capital expenditures

  (139,700

Less: Maintenance capital expenditures

  (67,400
  

 

 

 

Distributable cash flow attributable to common limited partners and the general partner

$ 228,850   
  

 

 

 

Cash Distributions(2):

Common limited partner units owned by 3rd parties

$ 149,700   

Common limited partner units owned by New Atlas

  49,600   
  

 

 

 

Total cash distributions to common limited partner units

  199,300   

Incentive distribution rights and general partner 2% interest

  16,500   
  

 

 

 

Total cash distributions

$ 215,800   
  

 

 

 

Per limited partner unit

$ 2.36   

 

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     Year Ending
December 31,
2015
 

New Atlas cash distributions and dividends

  

Common limited partner units owned by New Atlas

   $ 49,600   

Incentive distribution rights and general partner 2% interest

     16,500   

Preferred limited partner dividends

     8,800   
  

 

 

 

Total cash distributions/dividends to New Atlas

$ 74,900   
  

 

 

 

Excess of distributable cash flow after cash distributions

$ 13,050   
  

 

 

 

New Atlas

Revenues:

Atlas Resource Partners, L.P. revenue

$ 905,100   

Development Subsidiary revenue

  56,600   

Direct gas and oil production

  13,475   

Other

  1,725   
  

 

 

 

Total revenues

  976,900   
  

 

 

 

Costs and Expenses:

Atlas Resource Partners, L.P. costs and expenses

  771,000   

Development Subsidiary costs and expenses

  26,300   

Direct gas and oil production

  6,200   

General and administrative expense

  9,050   

Depreciation, depletion and amortization

  5,500   
  

 

 

 

Total costs and expenses

  818,050   
  

 

 

 

Operating income

  158,850   

Atlas Resource Partners, L.P. interest expense

  (82,025

Interest expense

  (17,150
  

 

 

 

Net income

$ 59,675   
  

 

 

 

Plus:

Atlas Resource Partners, L.P. interest expense

  82,025   

Interest expense

  17,150   

Depreciation, depletion and amortization

  5,500   
  

 

 

 

EBITDA

  164,350   

Less: Atlas Resource Partners, L.P. operating income

  (134,100

Plus: Atlas Resource Partners, L.P. cash distributions

  74,900   

Less: Development Subsidiary operating income

  (30,300

Plus: Development Subsidiary cash distributions and fees earned

  3,000   
  

 

 

 

Adjusted EBITDA

  77,850   

Less: Interest expense

  (17,150

Plus: Amortization of deferred finance costs

  1,400   

Less: Maintenance capital expenditures

  (1,600
  

 

 

 

Distributable cash flow

$ 60,500   
  

 

 

 

Cash distributions:

Initial distribution per common unit

$ 1.10   

Common units outstanding

  52,500   
  

 

 

 

Aggregate initial distributions to common unitholders

$ 57,750   
  

 

 

 

Excess of distributable cash flow after cash distributions

$ 2,750   
  

 

 

 

 

(1)  Amounts may not recalculate due to rounding.
(2)  These amounts assume an average of 84.4 million ARP common limited partner units outstanding for the period.

 

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Significant Forecast Assumptions

The forecast has been prepared by and is the responsibility of management. The forecast reflects management’s judgment as of the date of this information statement of conditions we expect to exist and the course of action we expect to take during the year ending December 31, 2015. While the assumptions discussed below are not all-inclusive, they include those that we believe are material to our forecasted results of operations, and any assumptions not discussed below were not deemed to be material. We believe we have a reasonable, objective basis for these assumptions. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There will likely be differences between our forecast and our actual results and those differences could be material. If the forecasted results are not achieved, we may not be able to make cash distributions on our common units at the quarterly distribution rate.

Atlas Resource Partners, L.P. Significant Forecast Assumptions

Our cash flow is currently generated principally from cash distributions we receive from ARP. For the year ending December 31, 2015, we have forecasted that ARP will generate operating income of $134.1 million, or approximately 84% of our $158.9 million of operating income for the period. In addition, we have forecasted that ARP will pay us $74.9 million of cash distributions for the year ending December 31, 2015, or approximately 96% of our $77.9 million of Adjusted EBITDA for the period. As such, we have reflected in the table below the significant forecast assumptions for ARP’s operations, revenues and expenses for the year ending December 31, 2015:

 

           Historical  
     Year
Ending
December 31,
2015
    Twelve
Months
Ended
September 30,
2014
    Year Ended
December 31,
2013
 

Revenues:

      

Gas and oil production key assumptions:

      

Wells initiated:

      

Gross

     133        126        103   

Net(1)

     53        69        66   

Wells connected:

      

Gross

     144        124        117   

Net(1)

     58        74        80   

Net production volume per day:

      

Natural gas (mcfd)

     221,443        226,948        158,886   

Crude oil (bpd)

     7,179        2,421        1,329   

NGL (bpd)

     4,408        3,683        3,473   
  

 

 

   

 

 

   

 

 

 

Total (mcfed)

  290,964      263,577      187,701   
  

 

 

   

 

 

   

 

 

 

Average sales prices:

Natural Gas (per Mcf):

Total realized price, after hedges

$ 3.74    $ 3.75    $ 3.47   

Total realized price, before hedges

$ 3.22    $ 3.84    $ 3.25   

Hedge percentage (on production volume)

  72   77   79

Basis and btu differentials included in pricing

$ (0.31 $ (0.41 $ (0.37

Crude oil (per Bbl):

Total realized price, after hedges

$ 78.15    $ 89.83    $ 91.01   

Total realized price, before hedges

$ 62.72    $ 93.55    $ 95.88   

Hedge percentage (on production volume)

  68   91   100

Basis differentials included in pricing

$ (5.00 $ (5.11 $ (2.04

 

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           Historical  
     Year
Ending
December 31,
2015
    Twelve
Months
Ended
September 30,
2014
    Year Ended
December 31,
2013
 

NGL (per Bbl):

      

Total realized price, after hedges

   $ 22.50      $ 30.59      $ 28.71   

Total realized price, before hedges

   $ 18.63      $ 32.13      $ 29.43   

Hedge percentage (on production volume)

     26     38     18

Partnership management key assumptions:

      

Partnership management funds raised (in millions)

   $ 275.0      $ 155.6      $ 150.0   

Partnership management wells initiated

     97        101        75   

Well construction and completion cost mark-up

     15     15     15

Administration and oversight—fee per well initiated

    
 
$100,000 to
$500,000
  
  
   
 
$100,000 to
$400,000
  
  
   
 
$100,000 to
$400,000
  
  

Administration and oversight fee per well per month

   $ 75      $ 75      $ 75   

Gross well services per well fee

    
 
$100 to
$2,000
  
  
   
 
$100 to
$2,000
  
  
   
 
$100 to
$2,000
  
  

Expenses:

      

Gas and oil production key assumptions:

      

Production costs (per Mcfe):

      

Lease operating expenses

   $ 1.43      $ 1.21      $ 1.09   

Production taxes

     0.27        0.25        0.18   

Transportation and compression

     0.25        0.26        0.24   
  

 

 

   

 

 

   

 

 

 

Total

$ 1.94    $ 1.73    $ 1.50   
  

 

 

   

 

 

   

 

 

 

 

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

Gas and oil production revenue. ARP’s forecasted natural gas and oil production volumes, net to its equity interest in the production of its investment partnerships and including its direct interests in producing wells, for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in its December 31, 2013 reserve report, and have been adjusted for current well performance and acquisition activity. The forecasted production volumes also include new production from an estimated 144 additional gross wells (58 net wells) ARP projects to connect during the year ending December 31, 2015, consisting of (i) 107 gross wells (34 net wells) which ARP intends to drill and connect on behalf of its investment partnerships and (ii) 37 gross direct interest wells (24 net wells), both of which ARP assumes will produce at rates consistent with wells of similar characteristics contained in its December 31, 2013 reserve report, adjusted for current well performance. ARP has assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance. Further, ARP has assumed no significant logistical issues related to new well hookups, such as delays in pipeline construction, permitting and right-of-ways which it primarily depends on gathering system service providers to complete.

Of the 133 additional wells that ARP projects to be initiated during the year ending December 31, 2015, 98 of the wells were recognized as proved, undeveloped locations at December 31, 2013, with total estimated reserves of 97 Bcfe. At the present time, ARP has no new information to adjust its reserve estimates for these wells and, as such, expect to convert 97 Bcfe of estimated reserves from proved undeveloped reserves to proved developed reserves. These wells are estimated to be connected at various dates through 2015, subject to change due to factors including operational issues and weather, and ARP estimates that these 98 wells will produce an aggregate gross production of 9 Bcfe (3 Bcfe net production) during the year ending December 31, 2015, subject to business plan changes, market factors and operational factors. The remaining 35 wells that ARP projects to

 

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initiate during the year ending December 31, 2015 are primarily related to projected drilling activities in Eagle Ford Shale, an acquisition which ARP completed in November 2014, and the Marcellus Shale, of which certain proved undeveloped locations were created through developmental drilling during the nine months ended September 30, 2014.

The 75.9 MMcfed increase in overall production from 187.7 MMcfed for the year ended December 31, 2013 to 263.6 MMcfed for the twelve months ended September 30, 2014 was principally due to partial year contributions from the EP Energy assets, which were acquired in July 2013, the GeoMet assets, which were acquired in April 2014, and the Rangely assets, which were acquired in June 2014, as well as production increases from new drilling, partially offset from natural production declines in other wells. The 27.4 MMcfed increase in overall production from 263.6 MMcfed for the twelve months ended September 30, 2014 to 291.0 MMcfed for the year ending December 31, 2015 is principally due to production from the Eagle Ford Shale assets, which ARP acquired in November 2014, and a full year of production from the acquisitions of the GeoMet and Rangely assets as well as production increases from new drilling, partially offset from natural production declines in other wells.

ARP’s forecasted commodity prices for the year ending December 31, 2015 were based upon average forward prices as of December 4, 2014, with natural gas and crude oil based upon prices quoted on the New York Mercantile Exchange, or NYMEX, and NGLs based upon Mont Belvieu, as quoted by the Oil Price Information Service, or OPIS, for a composite barrel, each on a first-day-of-the-month price. The actual prices that ARP realize for these commodities reflect various adjustments to the applicable NYMEX- and OPIS-based prices due to transportation, quality and regional price differentials, as well as the effect of ARP’s commodity price hedges. ARP’s forecasted estimated commodity prices are principally based on NYMEX and OPIS forward prices for the applicable commodities, but adjusted to take into account third-party market analysis and management’s own judgment.

ARP gas and oil production revenue for the year ending December 31, 2015 includes a $5.1 million reduction for the estimated impact of subordination of its production revenue to investor partners within its investment partnerships, compared with $12.0 million for the twelve months ended September 30, 2014 and $15.2 million for the year ended December 31, 2013. ARP’s decrease in the subordination of production revenue to investor partners within its investment partnerships between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

Gas and oil production costs and expenses. ARP’s estimated total natural gas and oil production costs and expenses consist of its equity interest in the production costs and expenses of its investment partnerships and as well as the production costs and expenses associated with its direct interests in producing wells. ARP’s lease operating expenses are comprised primarily of direct labor costs, repair and maintenance costs, and production materials. ARP total estimated production costs per mcfe for the year ending December 31, 2015 are $1.94 per mcfe, compared with $1.72 per mcfe for the twelve months ended September 30, 2014 and $1.50 per mcfe for the year ended December 31, 2013. The increase between the periods is primarily due to an increase in crude oil production volumes as a percentage of total production volumes. ARP’s production costs and expenses have a significant fixed cost component, such as labor and repair and maintenance costs, that cause increases in crude oil and NGL volumes, which generate fewer hydrocarbon production units than natural gas, to result in an increase in production costs per mcfe as oil and NGL volumes increase as a percentage of total volumes.

ARP gas and oil production costs and expenses for the year ending December 31, 2015 includes a $2.4 million reduction for the estimated impact of its proportionate share of lease operating expenses associated with the subordination of its production revenue to investor partners within its investment partnerships, compared with $4.2 million for the twelve months ended September 30, 2014 and $5.6 million for the year ended December 31, 2013. ARP’s decrease in the proportionate share of lease operating expenses associated with the subordination of its production revenue between the year ending December 31, 2015 and the twelve months ended September 30, 2014 and the year ended December 31, 2013 is due primarily to improved performance of certain programs and other programs concluding their subordination period.

 

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Partnership management revenue and costs and expenses. ARP has estimated that it will raise approximately $275.0 million through its investment partnerships during the year ending December 31, 2015 and that its equity interest in such partnerships will be approximately 28.5%. ARP also estimated that it will raise approximately $225.0 million through its investment partnerships during the year ending December 31, 2014, and that its equity interest in such partnerships will be approximately 32.6%.

For the administration and oversight monthly fee for each investment partnership well of $75, ARP has estimated that it will charge the fee on approximately 4,625 investment partnership wells for the year ending December 31, 2015. For the well services monthly fee for each operated investment partnership well of $100 to $2,000, ARP has estimated that it will charge the fee on approximately 4,925 investment partnership wells for the year ending December 31, 2015. Well services revenue also includes fees for services ARP personnel perform on investment partnership wells. ARP estimates that its well services profit margin will be approximately 62% for the year ending December 31, 2015, compared with 57% for the twelve months ended September 30, 2014 and 51% for the year ended December 31, 2013. The increase in profit margin between these periods is primarily due to an increase in service fees charged to investment partnership wells for ARP’s salt water gathering and disposal systems in the Mississippi Lime and Marble Falls areas, which generally have lower ongoing operating and maintenance costs as a percentage of service fees charged than other well service fees.

General and administrative expense. ARP has forecasted general and administrative expense of $45.9 million for the year ending December 31, 2015, as compared with $65.2 million for the twelve months ended September 30, 2014 and $78.1 million for the year ended December 31, 2013. The decrease in general and administrative expense between the forecasted year ending December 31, 2015 and the twelve month periods ended September 30, 2014 and December 31, 2013 is due primarily to costs incurred during the historical periods related to consummated acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2014. ARP did not include any consummated acquisitions in its forecast for the year ending December 31, 2015.

Interest expense. ARP has estimated that its interest expense for the year ending December 31, 2015 will be approximately $82.1 million, compared with $55.2 million for the twelve months ended September 30, 2014 and $34.3 million for the year ended December 31, 2013. The increase in interest expense between these periods is primarily due to a full year of interest expense on borrowings under ARP’s senior secured credit facility and senior notes that were utilized to fund its historical capital expenditures and acquisitions, including the EP Energy assets in July 2013, the GeoMet assets in April 2014, and the Rangely assets in June 2013, as well as the Eagle Ford Shale assets, which ARP acquired in November 2014. ARP’s estimate of interest expense for the year ending December 31, 2015 is based upon the following significant assumptions:

 

    $700.0 million of senior notes outstanding with a weighted average interest rate of 8.4%;

 

    approximately $760.0 million of weighted average borrowings outstanding on ARP’s senior secured credit facility, including borrowings to fund forecasted capital expenditures for the year ending December 31, 2015, at a weighted average interest rate of 2.6%, which is based upon an estimated London Interbank Offer Rate (also referred to as “LIBOR”) of 0.6%. ARP’s weighted LIBOR for the historical nine months ended September 30, 2014 was 0.2%;

 

    approximately $10.0 million of capitalized interest on borrowed funds related to capital projects only for periods that activities are in progress to bring these projects to their intended use; and

 

    approximately $1.2 million of commitment fees for the unused portion of ARP’s senior secured credit facility.

Preferred dividends. ARP has estimated that it will pay $19.0 million of preferred limited partner dividends for the year ending December 31, 2015, based upon an average of 3,665,000 units outstanding of its 8.625% Class D cumulative redeemable perpetual preferred units, 3,749,986 units outstanding of its Class C convertible preferred units at the same quarterly distribution rate to its common units, and 3,836,554 units outstanding of its

 

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Class B convertible preferred units at the same quarterly distribution rate to its common units. The Class B convertible preferred units are mandatorily convertible into an equivalent number common units on July 25, 2015.

Maintenance capital expenditures. Oil and gas assets naturally decline in future periods and, as such, ARP recognizes the estimated capitalized cost of stemming such decline in production margin for the purpose of stabilizing its cash available for distribution and cash distributions, which it refers to as maintenance capital expenditures. ARP calculates the estimate of maintenance capital expenditures by first multiplying its forecasted future full year production margin by its expected aggregate production decline of proved developed producing wells. Maintenance capital expenditures are then the estimated capitalized cost of wells that will generate an estimated first year margin equivalent to the production margin decline, assuming such wells are connected on the first day of the calendar year. ARP does not incur specific capital expenditures expressly for the purpose of maintaining or increasing production margin, but such amounts are a hypothetical subset of wells it expects to drill in future periods, including Marcellus Shale, Utica Shale, Mississippi Lime and Marble Falls wells, on undeveloped acreage already leased. Estimated capitalized cost of wells included within maintenance capital expenditures are also based upon relevant factors, including utilization of public forward commodity exchange prices, current estimates for regional pricing differentials, estimated labor and material rates and other production costs. ARP’s estimated maintenance capital expenditures for the year ending December 31, 2015 of $67.4 million, compared with $44.8 million and $28.2 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, are the sum of the estimate calculated the year ending December 31, 2014 plus estimates for the decline in production margin from new wells connected during the year ending December 31, 2015.

Expansion capital expenditures. ARP considers expansion capital expenditures to be any capital expenditure costs expended that are not maintenance capital expenditures—generally, this will include expenditures to increase, rather than maintain, production margin in future periods, as well as land, gathering and processing, and other non-drilling capital expenditures. ARP has estimated that it will incur $139.7 million of expansion capital expenditures for the year ending December 31, 2015, compared with $153.2 million and $232.0 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, primarily to drill direct interest and investment partnership wells. ARP expects its expansion capital expenditures to be funded through borrowings under its senior secured credit facility.

 

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New Atlas Significant Forecast Assumptions

We have reflected in the table below our significant forecast assumptions, other than for ARP’s operations, revenues and expenses previously detailed, for the year ending December 31, 2015:

 

           Historical  
     Year
Ending
December 31,
2015
    Twelve
Months
Ended
September 30,
2014
    Year Ended
December 31,
2013
 

Revenues:

      

New Atlas direct natural gas production key assumptions:

      

Net natural gas production volume per day (mcfd)(1)

     9,484        11,652        12,130   

Total realized price, after hedges

   $ 3.89      $ 3.84      $ 3.68   

Total realized price, before hedges

   $ 3.39      $ 3.94      $ 3.41   

Hedge percentage (on production volume)

     66     66     81

Basis and btu differentials included in pricing

   $ (0.15   $ (0.36   $ (0.16

Development Subsidiary gas and oil production key assumptions:

      

Net production volume per day:

      

Natural gas (mcfd)

     1,347        511        21   

Crude oil (bpd)

     2,316        97        7   

NGL (bpd)

     220        66        3   
  

 

 

   

 

 

   

 

 

 

Total (mcfed)

  16,561      1,491      79   
  

 

 

   

 

 

   

 

 

 

Average sales prices:

Natural Gas realized price (per Mcf)

$ 3.37    $ 4.20    $ 3.63   

Crude oil realized price (per Bbl)

$ 62.92    $ 93.50    $ 93.16   

NGL realized price (per Bbl)

$ 22.05    $ 31.58    $ 34.88   

Expenses:

New Atlas direct natural gas production key assumptions:

Production costs (per Mcfe)

$ 1.80    $ 1.47    $ 1.54   

Development Subsidiary gas and oil production key assumptions:

Production costs (per Mcfe)

$ 1.26    $ 3.00    $ 2.77   

 

(1)  The historical data for the twelve month periods ended September 30, 2014 and December 31, 2013 reflect production volume from July 31, 2013, the date of acquisition, through the end of the respective period, and are reflected on a per day basis based upon the number of days in the period from the acquisition date.

New Atlas direct natural gas production revenue. Our forecasted direct net natural gas production volumes for the year ending December 31, 2015 assumes that currently producing wells will produce at the rates forecasted in Atlas Energy’s December 31, 2013 reserve report, and have been adjusted for current well performance. The forecasted production volume does not include production from any new wells drilled and connected during the year ending December 31, 2015. We have assumed no significant interruptions of production volumes due to mechanical issues such as compressor breakdowns and sales line maintenance.

Our forecasted natural gas price for the year ending December 31, 2015 was based upon the average forward prices as of December 4, 2014, which was based upon prices quoted on NYMEX on a first-day-of-the-month price. The actual prices that we realize for natural gas reflect various adjustments to the NYMEX-based price due to regional price differentials, as well as the effect of our commodity price hedges. Our forecasted estimated commodity prices are principally based on NYMEX forward prices, but adjusted to take into account third-party market analysis and management’s own judgment.

 

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New Atlas direct natural gas production costs and expenses. Our production costs and expenses primarily consist of direct labor costs, repair and maintenance costs, production materials, transportation costs and severance taxes.

General and administrative expense. We have forecasted general and administrative expense of $9.1 million for the year ending December 31, 2015, as compared with $7.4 million and $7.6 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively.

Interest expense. In accordance with the Atlas merger agreement and the separation and distribution agreement, prior to the distribution, New Atlas will enter into one or more financing arrangements pursuant to which it will transfer $150.0 million to Atlas Energy as a cash distribution. Atlas Energy will use this cash distribution as well as a payment due from Targa Resources under the Atlas merger agreement to repay Atlas Energy’s outstanding indebtedness at or prior to the effective time of the distribution. For more information, see the section entitled “Certain Relationships and Related Party Transactions—Separation and Distribution Agreement—Cash Transfers.” New Atlas currently expects to enter into a term loan similar to Atlas Energy’s currently outstanding term loan to effect these financing arrangements. We have therefore assumed that we will issue a term loan of approximately $155.0 million, with net proceeds received of approximately $150.0 million, at an interest rate of 10.0% for the year ending December 31, 2015. As such, we have estimated interest expense for the year ending December 31, 2015 of $17.2 million, compared with $11.3 million and $5.4 million of interest expense for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively, which reflect the allocation of interest expense associated with Atlas Energy’s term loan for those historical periods prior to the separation and distribution. The increase in interest expense between the twelve months ended September 30, 2014 and the year ended December 31, 2013 is primarily due to a full year of interest expense on ATLS term loan, which was issued in July 2013.

In preparing the estimates, we and ARP have assumed that there will be no material change in the following matters, and thus they will have no impact on our cash available for distribution:

 

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

 

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

 

    We and ARP will not undertake any extraordinary transactions that would materially affect our or ARP’s cash flow; and

 

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

While we and ARP believe that the assumptions we used in preparing the estimates set forth above are reasonable based upon management’s current expectations concerning future events, they are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those described in “Risk Factors” elsewhere in this information statement that could cause actual results to differ materially from those we anticipate. If our and ARP assumptions are not realized, the actual available cash that we and ARP generate could be substantially less than the amount we currently estimate and could, therefore, be insufficient to permit us to pay the initial quarterly distribution or any amount on all of our outstanding units with respect to the four calendar quarters for the year ending December 31, 2015 or thereafter, in which event the market price of the common units may decline materially.

Sensitivity Analysis

Our ability to generate sufficient cash from our operations and cash distributions from ARP to pay cash distributions to our unitholders at the initial quarterly cash distribution rate for the year ending December 31, 2015 is a function of the following primary variables:

 

    The amount of hydrocarbons we and ARP produce;

 

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    The price at which we and ARP sell our hydrocarbons; and

 

    The amount of funds raised from ARP’s investment partnerships.

In the paragraphs below, we discuss the impact that changes in these variables, holding all other variables constant, would have on our ability to generate sufficient cash from our operations, including cash distributions received from ARP, to pay the initial quarterly cash distributions on our outstanding units.

Production volume changes. For purposes of our estimates set forth above, ARP has assumed that its net production is approximately 106.2 Bcfe during the year ending December 31, 2015. If ARP’s actual net production realized during the year ending December 31, 2015 is 10% more (or 10% less) than such estimate (that is, if actual net realized production is 95.6 Bcfe or 116.8 Bcfe, representing a pro rata change in natural gas, oil and NGLs), we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $30.0 million. Also, we have assumed that our net production from direct gas and oil production will total 3.5 Bcfe during the year ending December 31, 2015. If our actual net production realized during the year ending December 31, 2015 is 10% (or 10% less) than such estimate (that is, if actual net realized production is 3.1 Bcfe or 3.8 Bcfe), we estimate that our estimated cash available to pay cash distributions would change by approximately $0.7 million.

Commodity price changes. For purposes of our estimates set forth above, ARP has assumed that its weighted average net realized commodity price before hedges for its net production volumes is $3.22 per Mcf for natural gas, $62.72 per barrel for crude oil and $18.63 per barrel for NGLs. If the average realized commodity price for ARP’s net production volumes that are unhedged were to change by 10%, we estimate that ARP’s estimated cash available to pay cash distributions would change by approximately $13.9 million, assuming no changes in any other variables and inclusive of ARP’s commodity derivative contracts. Also, we have assumed that our weighted average net realized natural gas price for our net production volume is $3.39 per Mcf for natural gas. If the average realized natural gas price for our net production volume that is unhedged were to change by 10%, we estimate that our estimated cash available to pay distributions would change by approximately $0.4 million, assuming no changes in any other variables and inclusive of our commodity derivative contracts.

Funds raised changes. For purposes of our estimates set forth above, ARP has assumed funds raised from its investment partnerships will total $275.0 million during the year ending December 31, 2015. If actual funds raised during such period are 10% more or less than our estimate, we estimate that our estimated cash available for distribution change by approximately $5.5 million.

Unaudited Pro Forma Available Cash for Distribution

On a pro forma basis, assuming the distribution of the New Atlas common units contemplated in this information statement occurred on July 1, 2013 for the twelve months ended September 30, 2014 and on January 1, 2013 for the year ended December 31, 2013, our cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been $64.4 million and $62.2 million, respectively. The amount of cash available for distribution we must generate to support the payment of our initial quarterly distributions for four quarters on our common units outstanding immediately after the distribution date for the New Atlas common units is $57.8 million (or an average of approximately $14.4 million per quarter). As a result, we would have had sufficient distributable cash flow to pay the full initial quarterly distributions on our common units for the twelve months ended September 30, 2014 and the year ended December 31, 2013.

On a pro forma basis, ARP’s cash available for distribution for the twelve months ended September 30, 2014 and the year ended December 31, 2013 would have been $243.1 million and $184.1 million, respectively. The amount of cash available for distribution ARP must generate to support the payment of its pro forma

 

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quarterly distributions on its limited partner units outstanding, the general partner 2% interest and incentive distribution rights for the pro forma twelve month periods ended September 30, 2014 and December 31, 2013 would have been $208.6 million and $208.0 million, respectively (based upon a forecasted cash distribution per limited partner unit of $2.36 for the year ending December 31, 2015, or $0.59 per quarter per limited partner unit). As a result, ARP would have had sufficient distributable cash flow to pay the pro forma quarterly distributions on its common units, general partner 2% interest and incentive distribution rights for the twelve months ended September 30, 2014 by $34.5 million, but insufficient distributable cash flow to pay such amounts for the year ended December 31, 2013 by $23.9 million. The shortfall for the year ended December 31, 2013 is primarily attributable to:

 

    lower historical cash flows from ARP’s Eagle Ford Shale assets, which were acquired in November 2014 and included as a pro forma adjustment, compared with the cash flows currently supporting ARP’s cash distribution due to increased production volume and well drilling activity during the nine months ended September 30, 2014. See “Business—Gas and Oil Acquisitions” beginning on page 162 for further information; and

 

    ARP’s forecast for the year ending December 31, 2015 assumes $275.0 million of funds raised from its investment partnerships, compared with $155.6 million and $150.0 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively. As such, neither pro forma period includes the fees associated with the deployment of the additional investment partnership funds raised. ARP estimates that it will raise $225.0 million from its investment partnerships for the year ending December 31, 2014.

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts do not purport to present our results of operations had the distribution of the New Atlas common units contemplated by this information statement actually been completed as of the dates indicated. In addition, the cash available for distributions is primarily a cash accounting concept, while our unaudited pro forma combined historical financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash for distributions only as a general indication of the amount of cash available for distributions that we might have generated had we been formed on the dates indicated.

The following table illustrates, on a pro forma basis, for the twelve months ended September 30, 2014 and the year ended December 31, 2013, the amount of cash that would have been available for distributions to our unitholders assuming in each case that the distribution of the New Atlas common units contemplated by this information statement had been consummated on the dates indicated.

 

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New Atlas

Unaudited Pro Forma Cash Available for Distributions(1)

 

     Four Fiscal Quarters
Ended
September 30, 2014
    Year Ended
December 31, 2013
 

Atlas Resource Partners, L.P.

    

Revenues:

    

Gas and oil production

   $ 595,643      $ 526,615   

Well construction and completion

     202,507        167,883   

Administration and oversight

     15,426        12,277   

Well services

     23,230        19,492   

Gathering and processing

     15,324        15,676   

Other

     476        24   
  

 

 

   

 

 

 

Total revenues

  852,606      741,967   
  

 

 

   

 

 

 

Costs and Expenses:

Gas and oil production

  208,984      200,513   

Well construction and completion

  176,093      145,985   

Well services

  10,031      9,515   

Gathering and processing

  16,145      18,012   

General and administrative expense

  48,399      48,140   

Depreciation, depletion and amortization

  269,169      192,818   

Asset impairment

  38,014      38,014   
  

 

 

   

 

 

 

Total costs and expenses

  766,835      652,997   
  

 

 

   

 

 

 

Operating income

  85,771      88,970   

Interest expense

  (72,076   (70,621

Loss on asset sales and disposals

  (638   (987
  

 

 

   

 

 

 

Net income (loss)

  13,057      17,362   

Preferred limited partner dividends

  (24,804   (24,804
  

 

 

   

 

 

 

Net loss attributable to common limited partners and the general partner

$ (11,747 $ (7,442
  

 

 

   

 

 

 

Plus:

Preferred limited partner dividends

  24,804      24,804   

Interest expense

  72,076      70,621   

Depreciation, depletion and amortization

  269,169      192,818   

Asset impairment

  38,014      38,014   
  

 

 

   

 

 

 

EBITDA

  392,316      318,815   

Plus: Non-cash loss on asset sales and disposals

  638      987   

Plus: Non-cash stock compensation expense

  8,813      12,679   
  

 

 

   

 

 

 

Adjusted EBITDA

  401,767      332,481   

Less: Interest expense

  (72,076   (70,621

Less: Preferred limited partner dividends

  (24,804   (24,804

Plus: Amortization of deferred finance costs

  8,225      7,075   

Less: Expansion capital expenditures

  153,226      232,037   

Plus: Financing for expansion capital expenditures

  (153,226   (232,037

Less: Maintenance capital expenditures

  (70,000   (60,000
  

 

 

   

 

 

 

Distributable cash flow attributable to common limited partners and the general partner

$ 243,112    $ 184,131   
  

 

 

   

 

 

 

Pro Forma Cash Distributions(2):

Common limited partner units owned by 3rd parties

$ 142,600    $ 142,000   

Common limited partner units owned by New Atlas

  49,500      49,500   
  

 

 

   

 

 

 

Total cash pro forma distributions to common limited partner units

  192,100      191,500   

Incentive distribution rights and general partner 2% interest

  16,500      16,500   
  

 

 

   

 

 

 

Total pro forma cash distributions

$ 208,600    $ 208,000   
  

 

 

   

 

 

 

Per limited partner unit

$ 2.36    $ 2.36   

 

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     Four Fiscal Quarters
Ended
September 30, 2014
    Year Ended
December 31, 2013
 

Pro Forma New Atlas cash distributions and dividends

    

Common limited partner units owned by New Atlas

   $ 49,500      $ 49,500   

Incentive distribution rights and general partner 2% interest

     16,500        16,500   

Preferred limited partner dividends

     8,800        8,800   
  

 

 

   

 

 

 

Total pro forma cash distributions/dividends to New Atlas

$ 74,800    $ 74,800   
  

 

 

   

 

 

 

Excess (shortfall) of distributable cash flow after pro forma cash distributions

$ 34,512    $ (23,869
  

 

 

   

 

 

 

New Atlas(3)

Revenues:

Atlas Resource Partners, L.P. revenue

$ 852,606    $ 741,967   

Development Subsidiary revenue

  4,865      302   

Direct gas and oil production

  16,318      16,349   

Other

  1,015      321   
  

 

 

   

 

 

 

Total revenues

  874,804      758,939   
  

 

 

   

 

 

 

Costs and Expenses:

Atlas Resource Partners, L.P. costs and expenses

  766,835      652,997   

Development Subsidiary costs and expenses

  10,649      3,945   

Direct gas and oil production

  6,255      6,561   

General and administrative expense

  5,618      6,011   

Depreciation, depletion and amortization

  6,676      5,869   
  

 

 

   

 

 

 

Total costs and expenses

  796,033      675,383   
  

 

 

   

 

 

 

Operating income

  78,771      83,556   

Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal

  (72,714   (71,608

Interest expense

  (16,900   (16,900
  

 

 

   

 

 

 

Net loss

$ (10,843 $ (4,952
  

 

 

   

 

 

 

Plus:

Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal

  72,714      71,608   

Interest expense

  16,900      16,900   

Depreciation, depletion and amortization

  6,676      5,869   
  

 

 

   

 

 

 

EBITDA

  85,447      89,425   

Less: Atlas Resource Partners, L.P. operating income

  (85,770   (88,970

Plus: Atlas Resource Partners, L.P. cash distributions

  74,800      74,800   

Less: Development Subsidiary operating income

  5,784      3,643   

Plus: Development Subsidiary cash distributions and fees earned

  414      40   
  

 

 

   

 

 

 

Adjusted EBITDA

  80,675      78,938   

Less: Interest expense

  (16,900   (16,900

Plus: Amortization of deferred finance costs

  1,400      1,400   

Less: Maintenance capital expenditures

  (1,200   (1,200
  

 

 

   

 

 

 

Distributable cash flow

$ 63,975    $ 62,238   
  

 

 

   

 

 

 

Pro forma cash distributions:

Initial distribution per common unit

$ 1.10    $ 1.10   

Common units outstanding

  52,500      52,500   
  

 

 

   

 

 

 

Aggregate pro forma initial distributions to common unitholders

$ 57,750    $ 57,750   
  

 

 

   

 

 

 

Excess of distributable cash flow after pro forma cash distributions

$ 6,225    $ 4,488   
  

 

 

   

 

 

 

 

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(1)  Amounts may not recalculate due to rounding.
(2)  Reflects pro forma distributions for the period shown based upon average ARP common limited partner units outstanding of 81.4 million and 81.2 million for the twelve month periods ended September 30, 2014 and December 31, 2013, respectively. Also reflects ARP’s forecasted cash distribution per limited partner unit of $2.36 for the year ending December 31, 2015, or $0.59 per quarter per limited partner unit. Cash distributions per common limited partner unit for the historical twelve month periods ended September 30, 2014 and December 31, 2013 were $2.33 and $2.19, respectively.
(3)  New Atlas’s financial results included within this Unaudited Pro Forma Cash Available for Distribution table have been adjusted from the amounts presented within the Unaudited Pro Forma Combined Financial Data included elsewhere within this information statement to reflect the pro forma results of ARP’s acquisitions of assets from GeoMet, Inc. (“GeoMet”) on May 12, 2014 and in the Eagle Ford Shale on November 5, 2014, as well as New Atlas’s acquisitions of assets from its Arkoma assets on July 25, 2013. Management of ARP and New Atlas determined that each transaction did not meet the Securities and Exchange Commission’s tests of significance when measured at the acquisition date and, as such, audited historical and pro forma financial statements were not prepared for both transactions. Management of New Atlas believes the inclusion of such data, which has been derived from the respective seller’s unaudited financial statements for the periods presented prior to their May 12, 2014, November 5, 2014 and July 25, 2013, respectively, dates of acquisition, provides a reader with a better understanding of New Atlas’s unaudited pro forma available cash for distribution for the periods presented. Management of New Atlas has also reflected pro forma adjustments to its and ARP’s financing of the transactions as well as maintenance capital expenditure assumptions for the pro forma periods. A summary of the pro forma adjustments to reflect the transactions are as follows:

 

    Year ended September 30, 2014  
    Unaudited
Pro Forma
    Arkoma     GeoMet     Eagle
Ford
Shale
    Adjustments     Adjusted
Unaudited
Pro Forma
 

Revenues:

           

Atlas Resource Partners, L.P. revenue

  $ 745,595      $ —        $ 23,333      $ 83,678      $ —        $ 852,606   

Direct gas and oil production

    16,318        —          —          —          —          16,318   

Development Subsidiary revenue and other

    5,880        —          —          —          —          5,880   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total revenues

  767,793      —        23,333      83,678      —        874,804   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Costs and Expenses:

Atlas Resource Partners, L.P. costs and expenses

  710,803      —        16,384      39,648      —        766,835   

Development Subsidiary costs and expenses

  10,649      —        —        —        —        10,649   

Direct gas and oil production

  6,255      —        —        —        —        6,255   

General and administrative expense

  5,695      (77   —        —        —        5,618   

Depreciation, depletion and amortization

  6,676      —        —        —        —        6,676   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total costs and expenses

  740,078      (77   16,384      39,648      —        796,033   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

  27,715      77      6,949      44,030      —        78,771   

Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal

  (65,028   —        —        (7,686   —        (72,714

Interest expense

  (16,900   —        —        —        —        (16,900
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

$ (54,213 $ 77    $ 6,949    $ 36,344    $ —      $ (10,843
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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     Year ended December 31, 2013  
     Unaudited
Pro Forma
    Arkoma     Geo Met      Eagle Ford
Shale
    Adjustments      Adjusted
Unaudited
Pro Forma
 

Revenues:

              

Atlas Resource Partners, L.P. revenue

   $ 664,336      $ —        $ 38,209       $ 39,422      $ —         $ 741,967   

Direct gas and oil production

     6,821        9,528        —           —          —           16,349   

Development Subsidiary revenue and other

     623        —          —           —          —           623   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total revenues

  671,780      9,528      38,209      39,422      —        758,939   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Costs and Expenses:

Atlas Resource Partners, L.P. costs and expenses

  602,564      —        31,388      19,046      —        652,998   

Development Subsidiary costs and expenses

  3,945      —        —        —        —        3,945   

Direct gas and oil production

  2,861      3,700      —        —        —        6,561   

General and administrative expense

  8,162      (2,151   —        —        —        6,011   

Depreciation, depletion and amortization

  3,020      2,849      —        —        —        5,869   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total costs and expenses

  620,552      4,398      31,388      19,046      —        675,384   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Operating income

  51,228      5,130      6,821      20,376      —        83,555   

Atlas Resource Partners, L.P. interest expense and loss on asset sale/disposal

  (63,921   —        —        (7,686   —        (71,607

Interest expense

  (16,900   —        —        —        —        (16,900
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Net income (loss)

$ (29,593 $ 5,130    $ 6,821    $ 12,690    $ —      $ (4,952
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

ARP’s Cash Distribution Policy

Minimum Quarterly Distributions

ARP currently intends to distribute to the holders of its common units, Class B preferred units and general partner Class A units at least a minimum quarterly distribution of $0.40 per unit, or $1.60 per unit per year, to holders of its Class C preferred units $0.51 per unit per quarter, or $2.04 per unit per year and to holders of its Class D preferred units a guaranteed payment of $0.54 per unit per quarter, or $2.16 per unit per year, representing the Class D preferred units’ stated distribution rate of 8.625%, to the extent ARP has sufficient available cash after it establishes appropriate reserves and pay fees and expenses, including payments to its general partner in reimbursement of costs and expenses it incurs on ARP’s behalf. ARP’s minimum quarterly distribution is intended to reflect the level of cash that it expects to be available for distribution per common unit, preferred unit and general partner Class A unit each quarter. There is no guarantee that ARP will pay the minimum quarterly distribution, or any distribution, in any quarter, and ARP will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default is existing under an ARP credit agreement.

It is our current policy, as ARP’s general partner, that ARP should raise its quarterly cash distribution only when the general partner believes that:

 

    ARP has sufficient reserves and liquidity for the proper conduct of its business; and

 

    ARP can maintain such an increased distribution level for a sustained period.

While this is ARP’s current policy, we, in our capacity as ARP’s general partner, may alter the policy in the future when and if we determine such alteration to be appropriate.

 

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Quarterly Distributions of Available Cash

ARP’s partnership agreement requires that it make distributions of all available cash (as defined in its partnership agreement) within 45 days after the end of each quarter, beginning with the quarter ending March 31, 2012, to holders of record on the applicable record date. For these purposes, “available cash” generally means, for any of ARP’s fiscal quarters:

 

    all cash on hand at the end of the quarter (including amounts available for working capital purposes under a credit facility, commercial paper facility or other similar financing arrangement);

 

    less the amount of cash reserves established by ARP’s general partner at the date of determination of available cash for the quarter in order to:

 

    provide for the proper conduct of ARP’s business (including reserves for working capital, operating expenses, future capital expenditures and credit needs and potential acquisitions);

 

    comply with applicable law and any of ARP’s debt instruments or other agreements; or

 

    provide funds for distributions to (1) ARP’s unitholders for any one or more of the next four quarters or (2) with respect to ARP’s incentive distribution rights (provided that ARP’s general partner may not establish cash reserves for future distributions on ARP’s common units and general partner Class A units unless it determines that the establishment of such reserves will not prevent ARP from distributing the minimum distribution on all common units and general partner Class A units);

 

    plus, if ARP’s general partner so determines, all or any portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter.

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

Operating Surplus and Capital Surplus

General

All cash ARP distributes to unitholders will be characterized as either “operating surplus” or “capital surplus.” ARP’s partnership agreement requires that it distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus

Operating surplus generally means:

 

    $60 million (as described below);

 

    plus all of ARP’s cash receipts after its separation from Atlas Energy, including working capital borrowings but excluding cash from (1) borrowings that are not working capital borrowings, (2) sales of equity and debt securities and (3) sales or other dispositions of assets outside the ordinary course of business;

 

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

 

   

plus cash distributions paid on equity securities that ARP may issue after its separation from Atlas Energy to finance all or a portion of the construction, acquisition, development, replacement or improvement of a capital asset (such as equipment or reserves) during the period beginning on the date that ARP enters into a binding obligation to commence the construction, acquisition, development or

 

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improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset begins producing in paying quantities, the date it is placed into service or the date that it is abandoned or disposed of;

 

    plus cash distributions paid (including incremental incentive distributions) on equity issued to pay the construction period interest on debt incurred (including periodic net payments under related interest rate swap arrangements), or to pay construction period distributions on equity issued, to finance the capital improvements or capital assets referred to above;

 

    less ARP’s operating expenditures (as defined below);

 

    less the amount of cash reserves established by ARP’s general partner to provide funds for future operating expenditures;

 

    less all working capital borrowings not repaid within twelve months after having been incurred or repaid within such twelve-month period with the proceeds of additional working capital borrowings;

 

    less any cash loss realized on disposition of an investment capital expenditure.

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

“Operating expenditures” is defined in ARP’s partnership agreement, and generally means all of ARP’s cash expenditures, including:

 

    taxes;

 

    reimbursement of expenses to ARP’s general partner and its affiliates;

 

    payments made in the ordinary course of business on hedge contracts;

 

    director and officer compensation;

 

    repayment of working capital borrowings;

 

    debt service payments; and

 

    estimated maintenance capital expenditures.

Operating expenditures do not include:

 

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

 

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

 

    expansion capital expenditures;

 

    actual maintenance capital expenditures;

 

    investment capital expenditures;

 

    payment of transaction expenses relating to interim capital transactions;

 

    distributions to ARP unitholders and distributions with respect to ARP’s incentive distribution rights; or

 

    repurchases of equity interests except to fund obligations under employee benefit plans.

 

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Operating surplus does not reflect actual cash on hand that is available for distribution to ARP unitholders. For example, it includes a provision that will enable ARP, if it chooses, to distribute as operating surplus up to $60 million of cash that ARP receives in the future from non-operating sources, such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including in the definition of operating surplus certain cash distributions on equity securities would be to increase operating surplus by the amount of the cash distributions. As a result, ARP may also distribute as operating surplus up to the amount of the cash distributions it receives from non-operating sources.

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

Capital Expenditures

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not.

Maintenance Capital Expenditures. Maintenance capital expenditures are those capital expenditures ARP expect to make on an ongoing basis to maintain its current production levels over the long term. ARP expects that a primary component of maintenance capital expenditures will be capital expenditures associated with the replacement of equipment and oil and natural gas reserves (including non-proved reserves attributable to undeveloped leasehold acreage and other similar assets), whether through the development, exploitation and production of an existing leasehold or the acquisition or development of a new oil or natural gas property, including to offset expected production declines from producing properties. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of a replacement asset that is paid in respect of the period beginning on the date that ARP enters into a binding obligation to commence construction or development of the replacement asset and ending on the earlier to occur of the date the replacement asset is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because ARP’s maintenance capital expenditures can be irregular, the amount of actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to ARP unitholders if ARP subtracted actual maintenance capital expenditures from operating surplus. To address this issue, ARP’s partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures (including estimated plugging and abandonment costs) necessary to maintain its asset base over the long term be subtracted from operating surplus each quarter as opposed to the actual amounts spent. The amount of estimated maintenance capital expenditures deducted from operating surplus is subject to review and change by the board of directors of ARP’s general partner at least once a year. ARP will make the estimate at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future estimated maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will affect ARP’s business. Any adjustment to this estimate will be prospective only.

 

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

 

    it will reduce the risk that maintenance capital expenditures in any one quarter will be large enough to render operating surplus less than the minimum quarterly distribution to be paid on all the units for that quarter;

 

    it will increase ARP’s ability to distribute as operating surplus cash it receives from non-operating sources;

 

    in quarters where estimated maintenance capital expenditures exceed actual maintenance capital expenditures, it will be more difficult for ARP to raise its distributions above the minimum quarterly distribution because the amount of estimated maintenance capital expenditures will reduce the amount of cash available for distribution to ARP unitholders, even in quarters where there are no corresponding actual capital expenditures; conversely, the use of estimated maintenance capital expenditures in calculating operating surplus will have the opposite effect for quarters in which actual maintenance capital expenditures exceed our estimated maintenance capital expenditures; and

 

    it will be more difficult for ARP to raise distribution above the minimum quarterly distribution and pay incentive distribution rights.

Expansion Capital Expenditures

Expansion capital expenditures are those capital expenditures that ARP expects will increase the production of its oil and gas properties over the long term. Examples of expansion capital expenditures include the acquisition of reserves or equipment, the acquisition of new leasehold interests, or the development, exploitation and production of an existing leasehold interest, to the extent such expenditures are incurred to increase the production of ARP’s oil and gas properties over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued (including incremental distributions on incentive distribution rights) to finance all or any portion of a capital improvement that is paid in respect of the period beginning on the date that ARP enters into a binding obligation to commence construction or development of the capital improvement and ending on the earlier to occur of the date the capital improvement is placed into service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment Capital Expenditures

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

Capital expenditures that are made in part for maintenance capital purposes and in part for investment capital or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by the board of directors of ARP’s general partner based upon its good faith determination.

 

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Definition of Capital Surplus

Capital surplus is defined in ARP’s partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Capital surplus would generally be generated by:

 

    borrowings (including sales of debt securities) other than working capital borrowings;

 

    sales of debt and equity securities; and

 

    sales or other dispositions of assets for cash, other than inventory, accounts receivable and other assets disposed of in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions

ARP treats all available cash distributed as distributed from operating surplus until the sum of all available cash distributed since ARP began operations equals its total operating surplus from such date until the end of the quarter that immediately preceded the distribution. ARP will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. Operating surplus includes up to $60 million that does not reflect actual cash on hand that is available for distribution to our unitholders. This provision enables ARP, if it so chooses, to distribute as operating surplus up to this amount of cash it receives in the future from non-operating sources such as asset sales, issuances of securities and borrowings that would otherwise be distributed as capital surplus. ARP does not currently anticipate that it will make any distributions from capital surplus.

Distributions of Available Cash from Operating Surplus

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

 

    first, 2% to the holders of ARP’s general partner Class A units (which are held by ARP’s general partner) and 98% to the holders of ARP’s Class B preferred units and Class D preferred units, each pro rata, until each Class B preferred unitholder has received $0.40 per outstanding Class B preferred unit and there has been distributed in respect of each Class D preferred unit then outstanding the amount specified in the certificate of designation for the Class D preferred units;

 

    second, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s Class C preferred units, each pro rata, until there has been distributed in respect of each Class C preferred unit then outstanding the amount specified in the certificate of designation for the Class C preferred units;

 

    third, to the holders of the incentive distribution rights, which will initially be New Atlas following the separation, (A) 13/85ths of such amount paid pursuant to “second” above that is between $0.46 per outstanding unit for such quarter, which we refer to as the “first target distribution,” and $0.50 per outstanding unit for such quarter, which we refer to as the “second target distribution”; (B) 23/75ths of such amount paid pursuant to “second” above that is between the second target distribution and $0.60 per outstanding unit for such quarter, which we refer to as the “third target distribution”; and (C) 48/50ths of such amount paid pursuant to “second” above that is over the third target distribution for such quarter;

 

    fourth, 2% to the holders of ARP’s general partner Class A units and 98% to the holders of ARP’s common units, each pro rata, until there has been distributed in respect of each common unit then outstanding an amount equal to the minimum quarterly distribution for such quarter;

 

  •<