Table of Contents
Index to Financial Statements

As filed with the Securities and Exchange Commission on February 16, 2010

Registration No. 333-                    

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

Chesapeake Midstream Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

 

 

Delaware   4922   80-0534394

(State or Other Jurisdiction of

Incorporation or Organization)

 

(Primary Standard Industrial

Classification Code Number)

 

(I.R.S. Employer

Identification Number)

777 NW Grand Boulevard

Oklahoma City, Oklahoma 73118

(405) 935-1500

(Address, Including Zip Code, and Telephone Number, Including Area Code, of

Registrant’s Principal Executive Offices)

J. Mike Stice

777 NW Grand Boulevard

Oklahoma City, Oklahoma 73118

(405) 935-1500

(Name, Address, Including Zip Code, and Telephone Number, Including Area

Code, of Agent for Service)

 

 

Copies to:

 

D. Alan Beck, Jr.

Alan P. Baden

Vinson & Elkins L.L.P.

1001 Fannin Street, Suite 2500

Houston, Texas 77002

(713) 758-2222

 

Joshua Davidson

Chris J. Arntzen

Baker Botts L.L.P.

One Shell Plaza

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

 

 

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

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

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

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act:

 

Large accelerated filer   ¨

   Accelerated filer   ¨

Non-accelerated filer   þ

   Smaller reporting company   ¨
(Do not check if a smaller reporting company)   

CALCULATION OF REGISTRATION FEE

 

 

Title of Each Class of

Securities To Be Registered

  Proposed Maximum Aggregate
Offering Price (1)(2)
  Amount of
Registration Fee

Common units representing limited partner interests

  $345,000,000   $24,599
 
 

 

(1) Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

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

 

 

 


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Index to Financial Statements

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

 

SUBJECT TO COMPLETION, DATED FEBRUARY 16, 2010

Common Units

Representing Limited Partner Interests

LOGO

Chesapeake Midstream Partners, L.P.

This is the initial public offering of our common units. We intend to use the net proceeds of this offering to repay borrowings under our revolving credit facility, to fund future capital expenditures and working capital and for other general partnership purposes, including acquisitions, if any. Please read “Use of Proceeds.”

Prior to this offering, there has been no public market for our common units. We currently estimate that the initial public offering price will be between $             and $             per common unit. We intend to apply to list our common units on the New York Stock Exchange under the symbol “CHM.”

We have granted the underwriters an option to purchase up to an additional              common units from us to cover over-allotments, if any, at the initial public offering price, less underwriting discounts and commissions, within 30 days from the date of this prospectus.

 

 

Investing in our common units involves risks. Please read “ Risk Factors ” beginning on page 18. These risks include the following:

 

   

We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us.

 

   

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

 

   

Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather could adversely affect our business and operating results.

 

   

Chesapeake and Global Infrastructure Partners, through their joint ownership of Chesapeake Midstream Ventures, indirectly own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Chesapeake, Global Infrastructure Partners and Chesapeake Midstream Ventures, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

 

   

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

 

   

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

 

   

You will experience immediate and substantial dilution in pro forma net tangible book value of $              per common unit.

 

   

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

 

 

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

 

 

 

     Per Common Unit    Total

Initial Public Offering Price

   $                 $             

Underwriting Discounts and Commissions (1)

   $                 $             

Proceeds Before Expenses to Us

   $                 $             

 

(1) Excludes an aggregate structuring fee payable to Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated that is equal to     % of the gross proceeds of this offering, or approximately $            .

 

 

The underwriters expect to deliver the common units to purchasers on or about                     , 2010.

 

 

 

Citi    Morgan Stanley

 

 

The date of this prospectus is                     , 2010.

 

 


Table of Contents
Index to Financial Statements

 

[ Inside Front Cover Art to Come ]

 

 

 


Table of Contents
Index to Financial Statements

Table of Contents

 

     Page

Summary

   1

Chesapeake Midstream Partners, L.P.

   1

Overview

   1

Our Assets and Areas of Operation

   3

Our Business Strategies

   3

Our Competitive Strengths

   4

Our Relationship with Chesapeake

   5

Our Relationship with GIP

   6

Risk Factors

   6

Principal Executive Offices and Internet Address

   7

Formation Transactions and Partnership Structure

   7

Our Management

   9

Summary of Conflicts of Interest and Fiduciary Duties

   9

The Offering

   10

Summary Historical and Unaudited Pro Forma Financial and Operating Data

   14

Non-GAAP Financial Measure

   16

Risk Factors

   18

Risks Related to Our Business

   18

Risks Inherent in an Investment in Us

   32

Tax Risks to Common Unitholders

   40

Use of Proceeds

   45

Capitalization

   46

Dilution

   47

Our Cash Distribution Policy and Restrictions on Distributions

   48

General

   48

Our Minimum Quarterly Distribution

   49

Unaudited Pro Forma Available Cash for the Year Ended December  31, 2008 and the Twelve Months Ended September 30, 2009

   51

Partnership Unaudited Pro Forma Available Cash

   52

Estimated Adjusted EBITDA for Year Ending December 31, 2010

   53

Partnership Statement of Estimated Adjusted EBITDA

   55

Assumptions and Considerations

   56

Provisions of our Partnership Agreement Relating to Cash Distributions

   60

Distributions of Available Cash

   60

Operating Surplus and Capital Surplus

   61

Capital Expenditures

   63

Subordination Period

   64

Distributions of Available Cash From Operating Surplus During the Subordination Period

   66

Distributions of Available Cash From Operating Surplus After the Subordination Period

   66

General Partner Interest and Incentive Distribution Rights

   67

Percentage Allocations of Available Cash From Operating Surplus

   68

General Partner’s Right to Reset Incentive Distribution Levels

   68

Distributions From Capital Surplus

   71

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

   71

Distributions of Cash Upon Liquidation

   72

Selected Historical and Unaudited Pro Forma Financial and Operating Data

   74

Management’s Discussion and Analysis of Financial Condition and Results of Operations

   77

Overview

   77

Chesapeake Midstream Partners, L.P. and Our Predecessor

   78

Our Gas Gathering Agreements

   78

Other Arrangements

   81

How We Evaluate Our Operations

   82

Items Impacting the Comparability of Our Financial Results

   83

General Trends and Outlook

   85

 

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Index to Financial Statements
     Page

Results of Operations—Combined Overview

   87

Liquidity and Capital Resources

   92

Critical Accounting Policies and Estimates

   95

Quantitative and Qualitative Disclosures About Market Risk

   97

Recent Accounting Pronouncements

   98

Industry

   100

General

   100

Service Types

   100

Typical Contractual Arrangements

   101

U.S. Natural Gas Fundamentals

   102

Overview of our Barnett Shale Region

   103

Overview of our Mid-Continent Region

   104

Business

   106

Our Partnership

   106

Our Assets and Areas of Operation

   107

Our Business Strategies

   108

Our Competitive Strengths

   109

Our Relationship with Chesapeake

   111

Our Relationship with GIP

   112

Chesapeake—Total Joint Venture

   113

Our Assets

   113

Competition

   116

Safety and Maintenance

   116

Regulation of Operations

   117

Environmental Matters

   118

Title to Properties and Rights-of-Way

   122

Employees

   123

Legal Proceedings

   123

Management

   124

Management of the Partnership

   124

Directors and Executive Officers

   125

Executive Compensation

   127

Compensation of Directors

   127

Compensation Discussion and Analysis

   127

Elements and Mix of Compensation

   129

Employment Agreements

   131

Management Incentive Compensation Plan

   134

Long-Term Incentive Plan

   134

Security Ownership of Certain Beneficial Owners and Management

   137

Certain Relationships and Related Party Transactions

   139

Distributions and Payments to Our General Partner and its Affiliates

   139

Agreements with Affiliates

   140

Conflicts of Interest and Fiduciary Duties

   150

Conflicts of Interest

   150

Fiduciary Duties

   155

Description of the Common Units

   158

The Units

   158

Transfer Agent and Registrar

   158

Transfer of Common Units

   158

The Partnership Agreement

   160

Organization and Duration

   160

Purpose

   160

Power of Attorney

   160

Cash Distributions

   160

Capital Contributions

   161

 

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Index to Financial Statements
     Page

Voting Rights

   161

Limited Liability

   162

Issuance of Additional Securities

   163

Amendment of the Partnership Agreement

   164

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

   166

Termination and Dissolution

   166

Liquidation and Distribution of Proceeds

   167

Withdrawal or Removal of Our General Partner

   167

Transfer of General Partner Units

   168

Transfer of Ownership Interests in the General Partner

   168

Transfer of Incentive Distribution Rights

   168

Change of Management Provisions

   169

Limited Call Right

   169

Ineligible Assignees; Redemption

   170

Non-Citizen Assignees; Redemption

   170

Meetings; Voting

   170

Status as Limited Partner

   171

Indemnification

   171

Reimbursement of Expenses

   172

Books and Reports

   172

Right to Inspect Our Books and Records

   172

Registration Rights

   173

Units Eligible for Future Sale

   174

Material Tax Consequences

   175

Partnership Status

   175

Limited Partner Status

   177

Tax Consequences of Unit Ownership

   177

Tax Treatment of Operations

   182

Disposition of Common Units

   183

Uniformity of Units

   185

Tax-Exempt Organizations and Other Investors

   186

Administrative Matters

   187

State, Local, Foreign and Other Tax Considerations

   189

Investment in Chesapeake Midstream Partners, L.P. by Employee Benefit Plans

   190

Underwriting

   192

Validity of the Common Units

   198

Experts

   198

Where You Can Find More Information

   198

Forward-Looking Statements

   198

Index to Financial Statements

   F-1

Appendix A Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P.

   A-1

Appendix B Glossary of Terms

   B-1

 

 

You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. Neither we nor the underwriters have authorized anyone to provide you with additional or different information. We and the underwriters are offering to sell, and seeking offers to buy, our common units only in jurisdictions where offers and sales are permitted. The information in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of our common units.

Until                     , 2010 (25 days after the date of this prospectus), all dealers that effect transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This delivery requirement is in addition to the obligation of dealers to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

 

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Index to Financial Statements

SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. Because it is abbreviated, this summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the consolidated historical and pro forma financial data and the notes to those financial statements and data. The information presented in this prospectus assumes (i) an initial public offering price of $              per common unit and (ii) unless otherwise indicated, that the underwriters’ option to purchase additional common units is not exercised. You should read “Risk Factors” beginning on page 18 for more information about important risks that you should consider carefully before investing in our common units. We include a glossary of some of the terms used in this prospectus as Appendix B.

Unless the context otherwise requires, as used in this prospectus (i) “Chesapeake Midstream Partners, L.P.,” “we,” “our,” “us” or like terms, when used in a historical context, refer to our Predecessor, as defined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Chesapeake Midstream Partners, L.P. and Our Predecessor,” and when used in the present tense or prospectively, refer to Chesapeake Midstream Partners, L.P. and its subsidiaries; provided, however, that references to “our assets,” “our systems” and similar descriptions of our business and operations relate only to the portion of our Predecessor to be contributed to us at the closing of this offering; (ii) “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK) and its subsidiaries and affiliates, other than Chesapeake Midstream Partners, L.P. and Chesapeake Midstream GP, L.L.C., our general partner; (iii) “Chesapeake Energy Corporation” refers to such entity individually, excluding its subsidiaries and affiliates; (iv) “GIP” refers to Global Infrastructure Partners—A, L.P. and affiliated funds managed by Global Infrastructure Management, LLC, and their respective subsidiaries and affiliates, through which such funds hold their interests in us and our general partner; (v) “Chesapeake Midstream Ventures” refers to Chesapeake Midstream Ventures, L.L.C., the sole member of our general partner; and (vi) “Total,” when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

Chesapeake Midstream Partners, L.P.

Overview

We are a limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts. Our gathering systems operate in our Barnett Shale region in north-central Texas and our Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service more than 1,500 wells in the core of the prolific Barnett Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. Our systems consist of approximately 2,810 miles of gathering pipelines, servicing over 3,500 natural gas wells. For the nine months ended September 30, 2009, our assets gathered approximately 1.5 Bcf of natural gas per day, ranking us among the largest natural gas gatherers in the U.S.

Our gas gathering systems primarily collect natural gas from unconventional resource plays, a growing source of U.S. natural gas supply that is generally characterized by low finding and development costs compared

 

 

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Index to Financial Statements

to conventional resource plays. These systems were historically operated by Chesapeake and are integral to Chesapeake’s operations in our Barnett Shale and Mid-Continent regions. Chesapeake is the second largest natural gas producer in the U.S. by volume of natural gas produced, the most active driller for natural gas in the U.S. by number of drilling rigs utilized and has built a leading unconventional resource base, including the Barnett Shale and Mid-Continent areas served by our gathering systems, as well as in the Haynesville, Fayetteville and Marcellus shales served by gathering systems owned by Chesapeake. We believe that we have the opportunity to expand our position as a leading gatherer of natural gas from unconventional resource plays because of (i) our substantial current midstream asset base in unconventional resource plays, (ii) our relationship with Chesapeake, which has significant midstream operations in other unconventional resource plays, and (iii) the contractual rights included in our long-term gas gathering and omnibus agreements, including our right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation.

We believe our limited exposure to direct commodity price risk, long-term contractual cash flow stability and conservative capital structure differentiate our business model. We generate substantially all of our revenues through long-term, fixed-fee contracts that limit our direct commodity price exposure. We have entered into 20-year natural gas gathering agreements with Chesapeake and Total, Chesapeake’s upstream joint venture partner in our Barnett Shale region. On January 25, 2010, Chesapeake closed its $2.25 billion Barnett Shale upstream joint venture arrangement with Total under which Total acquired a 25% non-operated interest in Chesapeake’s Barnett Shale acreage in exchange for a cash payment of $800 million and its agreement to provide funding for $1.45 billion of future drilling and completion expenditures. Total S.A. is the fifth largest integrated oil and gas company in the world based on market capitalization. We expect that Chesapeake’s drilling activity in our Barnett Shale region will increase as compared to its 2009 drilling activity in part as a result of this joint venture.

Pursuant to our 20-year gas gathering agreements, Chesapeake and Total have agreed to provide us with extensive acreage dedications in our Barnett Shale region and, with respect to our agreement with Chesapeake, our Mid-Continent region. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows:

 

   

10-year minimum volume commitments in our Barnett Shale region, which mitigate throughput volume variability;

 

   

fee redetermination mechanisms in our Barnett Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and

 

   

price escalators in our Barnett Shale and Mid-Continent regions, which annually increase our gathering rates.

We believe that the combination of our fixed-fee business model and these contractual protections provide us with long-term cash flow stability and a strong platform from which to grow our business. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

We intend to leverage our relationship with Chesapeake to pursue a growth strategy of increasing throughput on our existing assets, developing new midstream assets to support Chesapeake, Total and other producers, and selectively acquiring midstream assets from Chesapeake and third parties. In addition to the gathering systems already contributed to us in connection with our formation, Chesapeake owns and operates gathering systems outside our current areas of operation in, among other areas, the three other major U.S. shale plays: the Haynesville Shale in northwestern Louisiana and east Texas; the Fayetteville Shale in central

 

 

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Arkansas; and the Marcellus Shale in Pennsylvania, West Virginia and New York. Chesapeake’s expanding midstream asset base in these areas supports its leading acreage positions and consists of approximately 1,500 miles of gathering pipelines that gathered approximately 0.7 Bcf of natural gas per day for the three months ended September 30, 2009. Chesapeake’s remaining midstream businesses, including those in the Haynesville, Fayetteville and Marcellus shales, represent a significant potential growth opportunity for us. Under our omnibus agreement with Chesapeake, subject to certain exceptions, we have a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Our Assets and Areas of Operation

We generated approximately 73% of our revenues from our gathering systems in our Barnett Shale region and approximately 27% of our revenues from our gathering systems in our Mid-Continent region for the nine months ended September 30, 2009. The following table summarizes our average daily throughput and assets by region as of and for the nine months ended September 30, 2009:

 

Region

  

Location

(State(s))

  Average Throughput
(MMcf/d)
  Approximate
Length

(Miles)
  Approximate
Number of
Wells
Serviced
  Gas
Compression
(Horsepower) (1)

Barnett Shale

   TX   909   700   1,534   128,085

Mid-Continent

   TX, OK, NM, KS, AR   623   2,110   1,984   86,631
                  

Total

     1,532   2,810   3,518   214,716
                  

 

(1) Substantially all of our gas compression is provided by compression equipment leased from Chesapeake. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Compressor Master Rental and Servicing Agreement.”

Our Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following strategies:

 

   

Focus on High-Growth, Unconventional Plays . We are principally focused on natural gas gathering opportunities in our Barnett Shale region and several unconventional resource plays in our Mid-Continent region, including the Colony Granite Wash and Texas Panhandle Granite Wash plays, that we believe are cost-advantaged sources of natural gas supply and are positioned for continued significant production growth. The combination of our extensive operations in these areas and our relationship with Chesapeake, the second largest natural gas producer and the leading leasehold owner in U.S. unconventional resource plays, provides us the opportunity to become the leading natural gas gatherer from unconventional resource plays in the U.S.

 

   

Leverage Our Extensive Asset Base . We own and operate a high-quality, high-capacity asset base that will allow us to gather significant incremental natural gas volumes throughout our areas of operation. Our expansive geographic footprint and expertise in developing energy infrastructure in urban and suburban environments position us to accommodate additional volumes as Chesapeake and Total execute their drilling plans within our acreage dedication. In addition, we plan to further optimize our systems by attracting third-party volumes in areas where we expect to have available capacity.

 

   

Minimize Direct Commodity Price Exposure . Our business model seeks to minimize direct commodity price exposure and promote cash flow stability. We currently generate substantially all of our revenues

 

 

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pursuant to long-term, fixed-fee contracts, and we plan to maintain our focus on fixed-fee services as we grow our business. We also have reduced our exposure to fluctuations in volumes and revenues that may occur during periods of low natural gas prices through our long-term gas gathering agreements with Chesapeake and Total.

 

   

Grow Through Disciplined Development and Accretive Acquisitions . We plan to selectively pursue accretive acquisitions of developed midstream assets from Chesapeake and other parties and to pursue organic development that will complement and expand our existing operations. Our omnibus agreement provides us a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation.

Our Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

 

   

Well-Positioned Asset Base . Our gathering systems include extensive high-quality natural gas pipeline networks in our Barnett Shale and Mid-Continent regions, which include high-growth unconventional resource plays such as the Colony Granite Wash and Texas Panhandle Granite Wash. These unconventional resource plays represent an increasingly important source of U.S. natural gas supply, and we expect them to continue to be growth areas for Chesapeake and other producers. We believe that our geographically advantaged asset footprint, the scale of our systems and our expertise in gathering from unconventional resource plays, including developing energy infrastructure in urban and suburban environments, will enable us to expand our position as a leading gatherer of natural gas from unconventional resource plays.

 

   

Extensive Acreage Dedication and System Scale . We have significant embedded volume growth potential associated with our extensive acreage dedication from Chesapeake and Total. We estimate that the areas covered by our acreage dedications include more than 4,000 and 6,000 potential gross drilling locations in our Barnett Shale and Mid-Continent regions, respectively. Further, the scale and capacity of our systems in these active drilling plays position us to attract third-party volumes.

 

   

Long-Term Contracted Cash Flow Stability . We believe that our business model, including our fixed-fee contract structure and long-term gas gathering agreements, mitigates our exposure to direct commodity price risk and provides us with long-term cash flow stability. We have entered into long-term gas gathering agreements with Chesapeake and Total that include minimum volume commitments, periodic fee redeterminations and other contractual provisions that are intended to support the stability of our cash flows.

 

   

Relationship with Chesapeake . Our relationship with Chesapeake provides us with significant potential long-term growth opportunities. Chesapeake is the industry’s leader in unconventional natural gas drilling and production with leading positions in the Haynesville, Fayetteville and Marcellus shale plays in addition to its operations in our Barnett Shale and Mid-Continent regions. In addition to our support of Chesapeake’s key upstream operations in our Barnett Shale and Mid-Continent regions, Chesapeake is incentivized to grow our business because of its ownership interest in our general partner, incentive distribution rights and limited partner interests. Additionally, our omnibus agreement provides us a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation.

 

   

Experienced Midstream Management Team . Our senior officers have significant experience building, acquiring and managing midstream and other assets and will be focused on optimizing our existing business and expanding our operations through disciplined development and accretive acquisitions. The chief executive officer, chief operating officer and chief financial officer of our general partner

 

 

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average over 25 years of experience and previously held leadership positions at ConocoPhillips, The Williams Companies, Crosstex Energy and General Electric.

 

   

Conservative Capital Structure . We believe that our conservative capital structure will allow us to pursue organic growth opportunities and acquisitions even in challenging commodity price environments and periods of capital markets dislocation. At the closing of this offering and after using the net proceeds therefrom in the manner described in “Use of Proceeds,” we expect to have no outstanding indebtedness and $              million of liquidity in the form of cash on hand and undrawn borrowing capacity under our amended and restated $500 million syndicated revolving credit facility.

Our Relationship with Chesapeake

One of our principal strengths is our relationship with Chesapeake. Chesapeake is the second largest natural gas producer in the U.S. by volume of natural gas produced and is the most active driller for natural gas in the U.S. by number of drilling rigs utilized. As of September 30, 2009, Chesapeake owned interests in approximately 43,600 producing natural gas and oil wells, which produced approximately 2.4 Bcfe per day for the nine months ended September 30, 2009, 92% of which was natural gas. Chesapeake’s primary strategy focuses on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in the “Big Four” natural gas shale plays: the Barnett Shale, the Haynesville Shale, the Fayetteville Shale and the Marcellus Shale. Chesapeake also has substantial operations in various other established and developing plays, both conventional and unconventional.

At the closing of this offering, Chesapeake will indirectly own 50% of both our general partner and our incentive distribution rights through its ownership in Chesapeake Midstream Ventures. Chesapeake will also directly own an aggregate     % limited partner interest in us through its ownership of              common units and              subordinated units. Because of its disproportionate participation in any increases to our cash distributions through the incentive distribution rights, Chesapeake is positioned to directly benefit from dedicating additional natural gas volumes to our systems and facilitating organic growth opportunities and accretive acquisitions from itself or third parties. In addition, under our omnibus agreement, subject to certain exceptions, we have a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation, although Chesapeake will not be obligated to accept any offer we make. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Chesapeake’s designees to the board of directors of our general partner will be Aubrey K. McClendon, Chesapeake’s Chairman and Chief Executive Officer, and Marcus C. Rowland, Chesapeake’s Executive Vice President and Chief Financial Officer. We believe that these directors will provide us with superior insights into natural gas production dynamics, financial management, the capital markets and merger and acquisition opportunities.

Given our focus on gathering natural gas from unconventional resource plays, we believe that our relationship with Chesapeake is advantageous for the following reasons:

 

   

Chesapeake Is a Leader in Unconventional Natural Gas Technology and Production . Chesapeake has been developing expertise in horizontal drilling technology since shortly after its inception in 1989 and was one of the first companies to recognize the potential of unconventional natural gas resource plays in the U.S. During the past five years, Chesapeake has grown from the eighth largest natural gas producer in the U.S. to the second largest natural gas producer, measured by natural gas volumes produced, in large part as a result of its success in finding and developing unconventional natural gas assets. Chesapeake currently maintains an active drilling program and the largest leasehold position in

 

 

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the U.S. “Big Four” natural gas shale plays (5.3 million gross acres, of which less than 10% have been dedicated to us).

 

   

Our Operating Areas Are Core Growth Areas for Chesapeake . The natural gas gathered by our systems in our Barnett Shale and Mid-Continent regions represented approximately 38% and 26%, respectively, of Chesapeake’s total natural gas production during the nine months ended September 30, 2009. Chesapeake’s undeveloped reserves within these regions provide us with significant organic growth opportunities. Pursuant to their joint venture arrangement, Chesapeake and Total hold an aggregate approximate 400,000 gross acres in the greater Barnett Shale area as of January 2010, and Chesapeake expects to increase its operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth-quarter 2009 levels.

 

   

Gas Gathering Agreements . We have entered into 20-year natural gas gathering agreements with Chesapeake and Total pursuant to which Chesapeake and Total have agreed to provide us with acreage dedications within our Barnett Shale region and, with respect to our agreement with Chesapeake, our Mid-Continent region. These agreements include 10-year minimum volume commitments covering Barnett Shale region production and a periodic fee redetermination mechanism to account for variability in revenues, capital expenditures and compression expenses in our Barnett Shale region with Chesapeake and Total and, with respect to our Mid-Continent region, with Chesapeake. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

Our Relationship with GIP

At the closing of this offering, GIP will indirectly own 50% of both our general partner and our incentive distribution rights through its ownership in Chesapeake Midstream Ventures. GIP will also directly own an aggregate     % limited partner interest in us through its ownership of              common units and              subordinated units.

GIP is a $5.6 billion independent infrastructure investment fund with offices in New York, London, Hong Kong and Stamford, Connecticut and an affiliated office in Sydney. GIP focuses on investments in three core sectors: energy, transportation, and water/waste. GIP’s global team possesses deep experience in its target infrastructure sectors, operations and finance. Affiliates of Credit Suisse Group AG and General Electric Company were, along with GIP’s partners, founding investors of GIP. GIP’s interests in the energy sector include, among others, a 50/50 joint venture interest with El Paso Corporation in the 1.5 Bcf per day Ruby interstate pipeline project (under advanced development); Channelview, an 800 megawatt gas-fired cogeneration project in Texas; and a joint venture interest with ArcLight Capital Partners in Terra-Gen, one of the leading renewable power generation companies in the U.S.

GIP’s designees to the board of directors of our general partner will be Matthew C. Harris, a GIP partner and former Co-Head of Energy Investment Banking at Credit Suisse, and William A. Woodburn, a GIP partner and former President and Chief Executive Officer of GE Infrastructure. We believe that these directors will provide us with superior insights into the capital markets, merger and acquisition opportunities, process management and productivity optimization.

Risk Factors

An investment in our common units involves risks associated with our business, regulatory and legal matters, our limited partnership structure and the tax characteristics of our common units. Please read “Risk Factors” for a description of these and other risks.

 

 

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Principal Executive Offices and Internet Address

Our principal executive offices are located at 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118, and our telephone number is (405) 935-1500. We expect our website to be located at www.                         .com . We expect to make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission, which we refer to as the SEC, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

Formation Transactions and Partnership Structure

We are a Delaware limited partnership recently formed by Chesapeake and GIP to own, operate, develop and acquire midstream energy assets. At or prior to the closing of this offering, the following transactions, which we refer to as the formation transactions, will occur:

 

   

Chesapeake and GIP will contribute to us all of the membership interests of Chesapeake MLP Operating, L.L.C. , which owns a portion of the business of our Predecessor consisting of certain assets and operations which have historically been principally engaged in gathering, treating and compressing natural gas for Chesapeake and other producers (please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Chesapeake Midstream Partners, L.P. and Our Predecessor”);

 

   

we will issue to Chesapeake Midstream GP, L.L.C., our general partner,              general partner units representing a 2.0% general partner interest in us as well as our incentive distribution rights;

 

   

we will issue to Chesapeake              common units and              subordinated units, representing an aggregate     % limited partner interest in us;

 

   

we will issue to GIP              common units and              subordinated units, representing an aggregate     % limited partner interest in us;

 

   

we will receive net proceeds of $             million from the issuance and sale of              common units to the public, representing a     % limited partner interest in us, at an assumed initial offering price of $             per unit;

 

   

we will use the net proceeds from this offering in the manner described in “Use of Proceeds”;

 

   

we will enter into an amended and restated $500 million revolving credit facility and, after using the net proceeds from this offering in the manner described in “Use of Proceeds,” will have $500 million of long-term borrowing capacity available to us under this revolving credit facility;

 

   

we will enter into an omnibus agreement with Chesapeake and our general partner pursuant to which, among other things, (i) Chesapeake will agree to provide us with certain rights relating to certain future midstream business opportunities, (ii) we will agree to reimburse Chesapeake for certain general and administrative services provided to us, and (iii) the parties will agree to certain indemnification obligations; and

 

   

our general partner will enter into an amended and restated employee secondment agreement with Chesapeake, pursuant to which certain employees of Chesapeake will be under the control of our general partner and render services to us or on our behalf.

 

 

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The diagram below illustrates our organization and ownership based on total units outstanding after giving effect to the offering and the related formation transactions.

 

Public Common Units

       

Chesapeake Common Units

       

GIP Common Units

       

Chesapeake Subordinated Units

       

GIP Subordinated Units

       

General Partner Units

   2.0
      

Total

   100.0
      

LOGO

 

 

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Our Management

Our general partner has sole responsibility for conducting our business and for managing our operations and will be controlled by Chesapeake Midstream Ventures, which will be jointly owned and controlled by Chesapeake and GIP. Pursuant to an omnibus agreement, employee secondment agreement and shared services agreement that we will enter into at the closing of this offering, Chesapeake will be entitled to reimbursement for certain expenses that it incurs on our behalf. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement” and “—Employee Secondment Agreement.” In addition, we will reimburse our general partner and its affiliates for all expenses they incur or payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

The board of directors of our general partner will initially be comprised of seven members, two of whom will be designated by Chesapeake, two of whom will be designated by GIP and three of whom will be independent. Neither our general partner nor its board of directors will be elected by our unitholders. Chesapeake Midstream Ventures is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including our three independent directors.

As is common with publicly traded partnerships and in order to maximize operational flexibility, we will conduct our operations through subsidiaries. We will initially have one direct subsidiary, Chesapeake MLP Operating, L.L.C., a limited liability company that will conduct business itself and through its subsidiaries.

Summary of Conflicts of Interest and Fiduciary Duties

Our general partner has a legal duty to manage us in a manner beneficial to holders of our common and subordinated units. This legal duty originates in statutes and judicial decisions and is commonly referred to as a “fiduciary duty.” However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its owner, Chesapeake Midstream Ventures. Certain of the officers and directors of our general partner are also officers and directors of Chesapeake, GIP and/or Chesapeake Midstream Ventures. As a result, conflicts of interest will arise in the future between us and holders of our common and subordinated units, on the one hand, and Chesapeake, GIP, Chesapeake Midstream Ventures and our general partner, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of common and subordinated units, which in turn has an effect on whether our general partner receives incentive cash distributions.

Our partnership agreement limits the liability of, and reduces the fiduciary duties owed by, our general partner to holders of our common and subordinated units. Our partnership agreement also restricts the remedies available to holders of our common and subordinated units for actions that might otherwise constitute a breach of our general partner’s fiduciary duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under applicable state law.

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties.”

 

 

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The Offering

 

Common units offered to the public

             common units.

             common units, if the underwriters exercise in full their option to purchase additional common units.

 

Units outstanding after this offering

             common units and              subordinated units, each representing a 49.0% limited partner interest in us (             common units and subordinated units, representing     % and     % limited partner interests in us, respectively, if the underwriters exercise in full their option to purchase additional common units). Our general partner will own              general partner units representing a 2.0% general partner interest in us (             general partner units representing a 2.0% general partner interest in us if the underwriters exercise in full their option to purchase additional common units).

 

Use of proceeds

We expect to receive net proceeds from the issuance and sale of common units offered by this prospectus of approximately $             million, after deducting underwriting discounts and commissions, structuring fees and offering expenses. We intend to use these proceeds, together with net proceeds from any exercise of the underwriters’ option to purchase additional common units, to repay approximately $             million of borrowings outstanding under our revolving credit facility, to fund future capital expenditures and working capital and for other general partnership purposes, including acquisitions, if any.

Affiliates of Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are lenders under our revolving credit facility and, in that respect, will receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our revolving credit facility. Please read “Underwriting.”

 

Cash distributions

Our general partner will adopt a cash distribution policy that will require us to pay a minimum quarterly distribution of $             per unit ($             per unit on an annualized basis) to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. We refer to this cash as “available cash,” and it is defined in our partnership agreement included in this prospectus as Appendix A and in the glossary included in this prospectus as Appendix B. Our ability to pay the minimum quarterly distribution is subject to various restrictions and other factors described in more detail under the caption “Our Cash Distribution Policy and Restrictions on Distributions.” For the first quarter that we are publicly traded, we will pay investors in this offering a prorated distribution covering the period from the completion of this offering through June 30, 2010, based on the actual length of that period.

 

 

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Our partnership agreement requires that we distribute all of our available cash each quarter in the following manner:

 

   

first , 98.0% to the holders of common units and 2.0% to our general partner, until each common unit has received the minimum quarterly distribution of $            , plus any arrearages from prior quarters;

 

   

second , 98.0% to the holders of subordinated units and 2.0% to our general partner, until each subordinated unit has received the minimum quarterly distribution of $            ; and

 

   

third , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unit has received a distribution of $            .

If cash distributions to our unitholders exceed $             per unit in any quarter, our general partner will receive, in addition to distributions on its 2.0% general partner interest, increasing percentages, up to 48.0%, of the cash we distribute in excess of that amount. We refer to these distributions as “incentive distributions.” Please read “Provisions of our Partnership Agreement Relating to Cash Distributions.”

The amount of pro forma available cash generated during the year ended December 31, 2008 would have been sufficient to allow us to pay the full minimum quarterly distribution ($             per unit per quarter, or $             on an annualized basis) on all of our common units and a cash distribution of $             per unit per quarter ($             per unit on an annualized basis), or approximately     % of the minimum quarterly distribution, on all of our subordinated units for such period. The amount of pro forma available cash generated during the twelve months ended September 30, 2009 would have been sufficient to allow us to pay the full minimum quarterly distribution on all common units and a cash distribution of $             per quarter ($             on an annualized basis), or approximately     % of the minimum quarterly distribution, on all of our subordinated units for such period. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

We believe that, based on the Partnership Statement of Estimated Adjusted EBITDA included under the caption “Our Cash Distribution Policy and Restrictions on Distributions,” we will have sufficient cash available for distribution to pay the minimum quarterly distribution of $             per unit on all common and subordinated units and the corresponding distributions on our general partner’s 2.0% interest for the four quarters ending December 31, 2010. Please read “Risk Factors” and “Our Cash Distribution Policy and Restrictions on Distributions.”

 

Subordinated units

Chesapeake and GIP will initially own all of our subordinated units. The principal difference between our common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the

 

 

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common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

 

Conversion of subordinated units

The subordination period will end on the first business day after we have earned and paid at least (i) $             (the minimum quarterly distribution on an annualized basis) on each outstanding unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four quarter periods ending on or after June 30, 2013 or (ii) $             (150.0% of the annualized minimum quarterly distribution) on each outstanding unit and the corresponding distributions on our general partner’s 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding that date. For purposes of the foregoing test, our general partner may include as earned in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current calendar year under the minimum volume commitments of our gas gathering agreements.

In addition, the subordination period will end upon the removal of our general partner other than for cause if the units held by our general partner and its affiliates are not voted in favor of such removal.

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter will no longer be entitled to arrearages.

 

General partner’s right to reset the target distribution levels

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on the same percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

 

 

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Issuance of additional units

We can issue an unlimited number of units without the consent of our unitholders. Please read “Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Securities.”

 

Limited voting rights

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or continuing basis. Our general partner may not be removed except by a vote of the holders of at least 66  2 / 3 % of the outstanding units voting together as a single class, including any units owned by our general partner and its affiliates, including Chesapeake and GIP. Upon consummation of this offering, Chesapeake and GIP will own an aggregate of     % of our common and subordinated units. This will give Chesapeake and GIP the ability to prevent the involuntary removal of our general partner. Please read “The Partnership Agreement—Voting Rights.”

 

Limited call right

If at any time our general partner and its affiliates own more than 80% of the outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price that is not less than the then-current market price of the common units.

 

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2012, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be     % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $             per unit, we estimate that your average allocable federal taxable income per year will be no more than $             per unit. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

 

Material tax consequences

For a discussion of other material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the U.S., please read “Material Tax Consequences.”

 

Exchange listing

We intend to apply to list our common units on the New York Stock Exchange under the symbol “CHM.”

 

 

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Summary Historical and Unaudited Pro Forma Financial and Operating Data

The following table shows summary consolidated historical financial and operating data for our Predecessor and pro forma as adjusted financial and operating data for Chesapeake Midstream Partners, L.P. for the periods and as of the dates presented. The following table should be read in conjunction with “Selected Historical and Unaudited Pro Forma Financial and Operating Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. In connection with this offering, Chesapeake and GIP will contribute to us a portion of the business of our Predecessor consisting of certain assets and operations that have historically been principally engaged in gathering, treating and compressing natural gas for Chesapeake and its working interest partners and are currently held by Chesapeake MLP Operating, L.L.C. The historical financial statements included elsewhere in this prospectus reflect the assets, liabilities and operations of our Predecessor. Since our operations will only represent a portion of the operations of our Predecessor and due to other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting the Comparability of Our Financial Results,” our future results of operations will not be comparable to our Predecessor’s historical results.

Our Predecessor’s summary consolidated historical balance sheet data as of December 31, 2007 and 2008 and summary consolidated historical statement of income and cash flow data for the years ended December 31, 2006, 2007 and 2008 are derived from the audited historical consolidated financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s summary consolidated historical balance sheet data as of December 31, 2006 are derived from the audited historical consolidated financial statements of our Predecessor not included in this prospectus. Our Predecessor’s summary consolidated historical balance sheet data as of September 30, 2009 and summary consolidated historical statement of income and cash flow data for the nine months ended September 30, 2008 and 2009 are derived from the unaudited historical consolidated financial statements of our Predecessor included elsewhere in this prospectus.

Our summary pro forma as adjusted statement of income data for the year ended December 31, 2008 and the nine months ended September 30, 2009 and summary pro forma as adjusted balance sheet data as of September 30, 2009 are derived from the unaudited pro forma financial data of Chesapeake Midstream Partners, L.P. included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2009, in the case of the pro forma as adjusted balance sheet, and as of January 1, 2008, in the case of the pro forma as adjusted statements of operations for the year ended December 31, 2008, and for the nine months ended September 30, 2009. These transactions include:

 

   

the contribution by Chesapeake and GIP of a portion of the business of our Predecessor to us (constituting approximately 57% of the total assets of our Predecessor as of September 30, 2009);

 

   

the receipt by us of net proceeds of $             million from the issuance and sale of common units to the public at an assumed initial public offering price of $             per unit; and

 

   

the application of the net proceeds from this offering of approximately $             million in the manner described in “Use of Proceeds.”

The pro forma as adjusted financial data gives effect to an estimated $2.0 million of additional annual general and administration expenses we expect to incur as a result of being a publicly traded partnership. The pro forma as adjusted financial data does not give effect to our 20-year gas gathering agreements with Chesapeake or Total or any of the transaction documents that were originally entered into on September 30, 2009 in connection with the formation of the joint venture between Chesapeake and GIP. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

The following table includes our Predecessor’s historical and our pro forma Adjusted EBITDA, which have not been prepared in accordance with generally accepted accounting principles (“GAAP”). Adjusted EBITDA is

 

 

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presented because it is helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “—Non-GAAP Financial Measure” below.

 

    Predecessor Consolidated     Partnership Pro Forma
As Adjusted
    Year Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,
2008
    Nine Months
Ended
September 30,
2009
    2006     2007     2008     2008     2009      
                     

(unaudited)

   

(unaudited)

    (In thousands, except per-unit and operating data)

Statement of Income Data:

             

Revenues

  $ 100,590      $ 191,931      $ 332,783      $ 234,678      $ 358,921      $ 280,272      $ 275,718

Operating expenses

    34,914        77,589        141,803        97,419        146,604        117,860        110,174

General and administrative expense

    2,766        6,880        13,362        9,400        22,782        13,060        16,780

Depreciation and amortization expense

    9,761        24,505        47,558        31,529        65,477        39,550        52,513
                                                     

Total operating expenses

    47,441        108,974        202,723        138,348        234,863        170,470        179,467
                                                     

Operating income

    53,149        82,957        130,060        96,330        124,058        109,802        96,251

Interest expense

    —          —          1,871        —          347        411        1,162

(Gain) loss on sale of assets (1)

    —          —          (5,541     (6,242     44,566        —          13

Other expense (income)

    —          —          (278     (306     (29     —          25

Impairment of property, plant and equipment and other assets (2)

    —          —          30,000        —          90,207        30,000        90,207

Income tax expense (benefit) (3)

    19,931        31,109        (61,287     (62,986     6,341        (68,351     —  
                                                     

Net income (loss)

  $ 33,218      $ 51,848      $ 165,295      $ 165,864      $ (17,374   $ 147,742      $ 4,844
                                                     

General partner interest in net income

             

Common unitholders’ interest in net income

             

Subordinated unitholders’ interest in net income

             

Net income per common unit (basic and diluted)

            $        $  

Net income per subordinated unit (basic and diluted)

            $        $  

Balance Sheet Data (at period end):

             

Net property, plant and equipment

  $ 381,090      $ 965,801      $ 2,339,473        $ 2,870,547        $ 1,744,973

Total assets

    403,141        1,010,112        2,583,765          3,232,840          2,123,148

Revolving credit facility

    —          —          460,000          12,173          —  

Total equity

    325,951        847,421        1,793,269          2,996,403          2,019,186

Cash Flow Data:

             

Net cash provided by (used in):

             

Operating activities

  $ 55,587      $ 93,948      $ 236,774      $ 134,473      $ 100,748       

Investing activities

    (218,843     (563,564     (1,384,834     (867,786     (690,994    

Financing activities

    163,272        469,622        1,230,059        733,316        664,268       

Other Data:

             

Adjusted EBITDA (4)

  $ 62,910      $ 107,462      $ 177,896      $ 128,165      $ 189,564      $ 149,352      $ 148,739

Capital expenditures

    218,843        563,564        1,402,449        885,395        756,883       

Operating Data:

             

Throughput, MMcf/d

    588        1,018        1,585        1,529        2,089        1,315        1,532

Average rate per Mcf

  $ 0.47      $ 0.52      $ 0.58      $ 0.56      $ 0.63      $ 0.58      $ 0.66

 

(1) Our Predecessor recorded a $44.6 million loss on the disposal of certain non-core and non-strategic gathering systems for the nine months ended September 30, 2009 and a $6.2 million gain on the disposal of certain gathering systems sold by Chesapeake in conjunction with an upstream transaction for the nine months ended September 30, 2008.
(2) Our Predecessor recorded an $86.2 million impairment associated with certain gathering systems located in our Mid-Continent region that are not expected to have future cash flows in excess of the book value of the systems. These systems were subsequently contributed to us during the nine months ended September 30, 2009. Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our Predecessor’s $460 million credit facility. During the
  year ended December 31, 2008, our Predecessor recorded a $30.0 million impairment associated with certain of its treating assets as a result of an expected continued decline in throughput with respect to such assets.

 

 

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(3) Prior to February 2008, our Predecessor filed a consolidated federal income tax return and state returns as required with Chesapeake. In February 2008, upon and subsequent to contribution of assets to our Predecessor by Chesapeake, our Predecessor and certain of its subsidiaries became a partnership and limited liability companies, respectively, and were subsequently treated as pass through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. As such, our Predecessor has provided for the change in legal structure which occurred in 2008 by recording a $63 million income tax benefit for the nine months ended September 30, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our Predecessor’s remaining taxable entity that was not contributed to us.
(4) Adjusted EBITDA is defined in “—Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

Management believes it is appropriate to exclude unusual or non-recurring items from EBITDA because management believes these non-recurring, non-cash charges affect the comparability of operating results. We define Adjusted EBITDA as net income (loss) before income tax expense, interest expense, depreciation and amortization expense, certain non-cash charges, gains and losses from derivatives activities and selected items that are generally unusual or non-recurring. Adjusted EBITDA is a non-GAAP financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to capital structure, historical cost basis or financing methods;

 

   

our ability to incur and service debt and fund capital expenditures;

 

   

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA are net income and net cash provided by operating activities. Our non-GAAP financial measure of Adjusted EBITDA should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Adjusted EBITDA has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider Adjusted EBITDA in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA may be defined differently by other companies in our industry, our definition of Adjusted EBITDA may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

 

 

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The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measures of net income and net cash provided by operating activities on an historical and pro forma as adjusted basis:

 

    Predecessor Consolidated     Partnership Pro Forma
As Adjusted
    Year Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,

2008
    Nine Months
Ended
September 30,

2009
    2006   2007   2008     2008     2009      
    (In thousands)

Reconciliation of Adjusted EBITDA to Net Income:

             

Net income (loss)

  $ 33,218   $ 51,848   $ 165,295      $ 165,864      $ (17,374   $ 147,742      $ 4,844

Interest expense

    —       —       1,871        —          347        411        1,162

Income tax expense (benefit)

    19,931     31,109     (61,287     (62,986     6,341        (68,351     —  

Depreciation and amortization expense

    9,761     24,505     47,558        31,529        65,477        39,550        52,513

Impairment of property, plant and equipment and other assets

    —       —       30,000        —          90,207        30,000        90,207

(Gain) loss on sale of assets

    —       —       (5,541     (6,242     44,566        —          13
                                                 

Adjusted EBITDA

  $ 62,910   $ 107,462   $ 177,896      $ 128,165      $ 189,564      $ 149,352      $ 148,739
                                                 

Reconciliation of Adjusted EBITDA to Net Cash Provided by (used in) Operating Activities:

             

Net cash provided by (used in) operating activities

  $ 55,587   $ 93,948   $ 236,774      $ 134,473      $ 100,748       

Changes in assets and liabilities

    4,862     12,911     (61,286     (6,769     88,187       

Interest expense

    —       —       1,871        —          347       

Current income tax expense

    2,461     —       —          —          —         

Other non-cash items

    —       603     537        461        282       
                                       

Adjusted EBITDA

  $ 62,910   $ 107,462   $ 177,896      $ 128,165      $ 189,564       
                                       

 

 

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RISK FACTORS

Limited partner units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we might not be able to pay the minimum quarterly distribution on our common units, the trading price of our common units could decline and you could lose all or part of your investment in us.

Risks Related to Our Business

We are dependent on Chesapeake for a substantial majority of our revenues. Therefore, we are indirectly subject to the business risks of Chesapeake. We have no control over Chesapeake’s business decisions and operations, and Chesapeake is under no obligation to adopt a business strategy that favors us.

Historically, we have provided substantially all of our natural gas gathering, treating and compressing services to Chesapeake and its working interest partners. For the nine months ended September 30, 2009, Chesapeake and its working interest partners accounted for approximately 98% of the natural gas volumes on our gathering systems and our revenues on a pro forma basis. We expect to derive a substantial majority of our revenues from Chesapeake for the foreseeable future. Therefore, any event, whether in our area of operations or otherwise, that adversely affects Chesapeake’s production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are indirectly subject to the business risks of Chesapeake, some of which are the following:

 

   

the volatility of natural gas and oil prices, which could have a negative effect on the value of its oil and natural gas properties, its drilling programs or its ability to finance its operations;

 

   

the availability of capital on an economic basis to fund its exploration and development activities;

 

   

its ability to replace reserves, sustain production and begin production on certain leases that may otherwise expire;

 

   

uncertainties inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production;

 

   

its drilling and operating risks, including potential environmental liabilities;

 

   

transportation capacity constraints and interruptions;

 

   

adverse effects of governmental and environmental regulation; and

 

   

losses from pending or future litigation.

If Chesapeake and Total do not increase the volumes of natural gas they provide to our gathering systems, our growth strategy and ability to increase cash distributions to our unitholders may be adversely affected.

Unless we are successful in attracting significant unaffiliated third-party customers, our ability to increase the throughput on our gathering systems will be dependent on receiving increased volumes from Chesapeake and Total. Other than the scheduled increases in the minimum volume commitments provided for in our gas gathering agreements with Chesapeake and Total, neither Chesapeake nor Total is obligated to provide additional volumes to our systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. A reduction in the natural gas volumes supplied by Chesapeake and Total could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase cash distributions to our unitholders.

 

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We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

In order to pay the minimum quarterly distribution of $             per unit per quarter, or $             per unit per year, we will require available cash of approximately $             million per quarter, or $             million per year, based on the number of common and subordinated units to be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

   

the volume of natural gas we gather, treat and compress;

 

   

the level of production of, the demand for, and, indirectly, the price of natural gas;

 

   

the level of our operating and general and administrative costs;

 

   

regulatory action affecting the supply of or demand for natural gas, our operations, the rates we can charge, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and

 

   

prevailing economic conditions.

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

 

   

the level of capital expenditures we make, including capital expenditures for connecting new operated drilling pads or new operated wells of Chesapeake and Total in our acreage dedications as required by our gas gathering agreements;

 

   

the cost of acquisitions, if any;

 

   

our debt service requirements and other liabilities;

 

   

fluctuations in our working capital needs;

 

   

our ability to borrow funds and access capital markets;

 

   

restrictions contained in our debt agreements;

 

   

the amount of cash reserves established by our general partner; and

 

   

other business risks affecting our cash levels.

For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read “Our Cash Distribution Policy and Restrictions On Distributions.”

On a pro forma basis we would not have had sufficient cash available for distribution to pay the full minimum quarterly distribution on all units for the year ended December 31, 2008 or the twelve months ended September 30, 2009.

The amount of pro forma available cash generated during the year ended December 31, 2008 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only a cash distribution of approximately     % of the minimum quarterly distribution on all of our subordinated units for such period. The amount of pro forma available cash generated during the twelve months ended September 30, 2009 would have been sufficient to allow us to pay the full minimum quarterly distribution on all of our common units, but only a cash distribution of approximately     % of the minimum quarterly distribution on all of our subordinated units for such period. For a calculation of our ability to make cash distributions to our unitholders

 

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based on our pro forma results for 2008 and the twelve months ended September 30, 2009, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

The assumptions underlying the forecast of cash available for distribution that we include in “Our Cash Distribution Policy and Restrictions On Distributions” are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

The forecast of cash available for distribution set forth in “Our Cash Distribution Policy and Restrictions On Distributions” includes our forecasted results of operations, Adjusted EBITDA and cash available for distribution for the year ending December 31, 2010. The financial forecast has been prepared by management, and we have not received 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 that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common units or subordinated units, in which event the market price of our common units may decline materially.

Chesapeake’s level of indebtedness could adversely affect our ability to grow our business, our ability to make cash distributions to our unitholders and our credit ratings and profile.

Chesapeake must devote a portion of its cash flows from operating activities to service its indebtedness, and such cash flows are therefore not available for further development activities, which may reduce the volumes Chesapeake delivers to our gathering systems. Furthermore, a higher level of indebtedness at Chesapeake increases the risk that it may default on its obligations, including under its gas gathering agreement with us. Such a default could occur after the conversion of the subordinated units as a result of our general partner’s ability, for purposes of testing whether the subordination period has ended, to include as “earned” in a particular quarter its prorated estimates of shortfall payments to be earned by the end of the then current calendar year under the minimum volume commitments of our gas gathering agreements. As of September 30, 2009, Chesapeake had long-term indebtedness of approximately $12.1 billion, with $1.6 billion of outstanding borrowings drawn under its $3.5 billion revolving credit facility and $12.2 million of outstanding borrowings drawn under its $250 million and $500 million midstream revolving credit facilities. The covenants contained in the agreements governing Chesapeake’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments, which also may reduce the volumes Chesapeake delivers to our gathering systems.

Chesapeake’s long-term credit ratings are currently below investment grade, with corporate credit ratings of Ba2 and BB from Moody’s and Standard & Poor’s, respectively. If these ratings are lowered in the future, the interest rate and fees Chesapeake pays on its revolving credit facilities will increase. In addition, although we will not have any indebtedness rated by any credit rating agency at the closing of this offering, we may have rated debt in the future. Credit rating agencies such as Standard & Poor’s and Moody’s will likely consider Chesapeake’s debt ratings when assigning ours because of Chesapeake’s ownership interest in us, the significant commercial relationships between Chesapeake and us, and our reliance on Chesapeake for a substantial majority of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of Chesapeake, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make cash distributions to our unitholders.

In addition to Chesapeake, we are dependent on Total for a significant amount of the natural gas that we gather, treat and compress. A material reduction in Total’s production gathered, treated or compressed by us may result in a material decline in our revenues and cash available for distribution.

We rely on Total for a significant amount of the natural gas that we gather, treat and compress. Total may suffer a decrease in production volumes in the areas serviced by us. We are also subject to the risk that Total may

 

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default on its obligations under its gas gathering agreement with us. Neither of our Total counterparties under our gas gathering agreement, nor the Total guarantor of those counterparties’ obligations, are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with a rated contract counterparty. A loss of a significant portion of the natural gas volumes supplied by Total, or any nonpayment or late payment by Total of our fees, could result in a material decline in our revenues and our cash available for distribution.

Because of the natural decline in production from existing wells in our areas of operation, our success depends on our ability to obtain new sources of natural gas, which is dependent on factors beyond our control. Any decrease in the volumes of natural gas that we gather could adversely affect our business and operating results.

The volumes that support our business are dependent on the level of production from natural gas wells connected to our gathering systems, the production from which may be less than we expect and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput levels on our gathering systems, we must obtain new sources of natural gas. The primary factors affecting our ability to obtain non-dedicated sources of natural gas include (i) the level of successful drilling activity near our systems and (ii) our ability to compete for volumes from successful new wells.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our gathering systems or the rate at which production from a well declines. In addition, we have no control over Chesapeake, Total or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for hydrocarbons, levels of reserves, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs, and other production and development costs.

Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported liquified natural gas, or LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional pricing differentials such as in the Mid-Continent; the price and availability of alternative fuels; the effect of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, LNG and other commodities. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering and treating assets. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain levels of throughput, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems in unconventional resource plays, as the basins in those plays generally have higher initial production rates and steeper production decline curves than wells in more conventional basins. Accordingly, volumes on our systems serving unconventional resource plays may need to be replaced at a faster rate to maintain or grow the current volumes than may be the case in other regions of production. In addition to significant capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to estimate higher maintenance capital expenditures over time, which will reduce our cash available for distribution from operating surplus.

 

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If either Chesapeake or Total terminates its gas gathering agreement with us as a result of our failure to perform certain obligations under their agreement, and in either case we are unable to secure comparable alternative arrangements, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders will be adversely affected.

Chesapeake and Total may terminate their respective gas gathering agreement with us if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods, provided, however, that if our failure to perform relates to only one or more facilities or gathering systems, Chesapeake or Total, as applicable, may terminate its agreement only as to such facilities or systems. Additionally, if a gas gathering agreement is terminated as to only a particular Barnett Shale gathering system, the minimum volume commitment may be reduced for gas volumes that would have been gathered on the terminated gathering system. After the termination of a gas gathering agreement, we cannot assure you that Chesapeake or Total, as applicable, will continue to contract with us to provide gathering services, that the terms of any renegotiated agreements will be as favorable as our existing agreements or that we will be able to enter into comparable alternative arrangements with third parties. To the extent Chesapeake or Total, as applicable, terminates its agreement or there is a reduction in our minimum volume commitments, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders may be adversely affected.

Certain of the provisions contained in our gas gathering agreements may not operate as intended, including the volumetric-based cap associated with fuel, lost and unaccounted for gas and electricity, which could subject us to direct commodity price risk and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

We cannot assure you that the provisions of our gas gathering agreements will operate as intended. Our gas gathering agreements contain provisions relating to, among other items, periodic fee redeterminations, changes in laws affecting our operations and fuel, lost and unaccounted for gas and electricity.

The fee redetermination and other provisions of our gas gathering agreements are intended to support the stability of our cash flows and were designed with the goal of supporting a return on our invested capital, which is not equivalent to ensuring that our business will generate a particular amount of cash flow. Our fee redetermination provisions do not take into consideration all expenses and other variables, including certain operating expenditures, that would affect our return on invested capital. In addition, our gathering rates may be adjusted upward or downward following a fee redetermination, subject to specified caps. The changes of law provisions contained in our gas gathering agreements are designed to provide for our reimbursement by Chesapeake and Total of certain taxes, fees, assessments and other charges that we may incur as a result of changes in law. These changes of law provisions may not cover all legal or regulatory changes that could have an adverse economic impact on our operations. We have also agreed with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas and electricity on our systems with respect to Chesapeake’s volumes. In the event that we exceed the permitted cap in any covered period, we may incur significant expenses to replace the volume of natural gas used as fuel, lost or unaccounted for, or electricity, in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

In the event these or other provisions of our gas gathering agreements do not operate as intended, our financial condition, results of operations, cash flows and ability to make distributions to our unitholders could be adversely affected.

We do not obtain independent evaluations of natural gas reserves connected to our gathering systems; therefore, in the future, volumes of natural gas on our systems could be less than we anticipate.

We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves.

 

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Notwithstanding the contractual protections in our gas gathering agreements with Chesapeake and Total, including 10-year minimum volume commitments in our Barnett Shale region and fee redetermination provisions, if the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We are generally required to make capital expenditures under our gas gathering agreements with Chesapeake and Total. If we are unable to obtain needed capital or financing on satisfactory terms to fund required capital expenditures or capital expenditures to otherwise expand our asset base, our ability to grow cash distributions may be diminished or our financial leverage could increase.

Under our gas gathering agreements, upon the request of either Chesapeake or Total, as applicable, we are generally required to connect new operated drilling pads and new operated wells in our Barnett Shale region during the minimum volume commitment period, and with respect to our Mid-Continent region prior to June 30, 2019, to use commercially reasonable efforts to do the same. In addition, in order to increase our overall asset base, we will need to make significant expansion capital expenditures in the future. If we do not make sufficient or effective expansion capital expenditures, including such new drilling pad and new well connections, we will be unable to expand our business operations and will be unable to raise the level of our future cash distributions. If we are delayed in making a connection to an operated drilling pad or well in the Barnett acreage dedication, Chesapeake or Total, as their sole remedy for such delayed connection, would be entitled to a delay in the minimum volume obligation for gas volumes that would have been produced from the delayed connections. Any delay in the minimum volume obligations for drilling pad or well connections could reduce our revenues under the gas gathering agreements and our cash distributions.

To the extent that our cash from operations is insufficient to fund our expansion capital expenditures, we may be required to incur borrowings or raise capital through public or private debt or equity offerings. Our ability to obtain bank financing or to access the capital markets may be limited by our financial condition at the time of any such financing or offering and the covenants in our existing debt agreements, as well as by general economic and capital market conditions and contingencies and uncertainties that are beyond our control. Even if we are successful in obtaining the necessary funds, the terms of such financings could limit our ability to pay distributions to our unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional common units may result in significant unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

We will be required to deduct estimated maintenance capital expenditures from operating surplus, which may result in less cash available for distribution to unitholders than if actual maintenance capital expenditures were deducted.

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

 

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Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.

We compete with similar enterprises in our areas of operation other than with respect to natural gas production dedicated to us pursuant to our gas gathering agreements with Chesapeake and Total. Our competitors may expand or construct gathering systems and associated infrastructure that would create additional competition for the services we provide to our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Part of our growth strategy is to attract volumes to our systems from unaffiliated third parties over time. However, we have historically provided gathering and related services to third parties on only a limited basis, and we can provide no assurance that we will be able to attract any material third-party volumes to our systems. Our efforts to attract new unaffiliated customers may be adversely affected by our need to prioritize allocating capital expenditures towards connecting new operated drilling pads and new operated wells for Chesapeake and Total as well as our desire to provide our services pursuant to fixed-fee contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements pursuant to which we would be required to assume some direct commodity price exposure. In addition, we will need to establish a reputation among our potential customer base for providing high quality service in order to successfully attract material volumes from unaffiliated third parties.

If third-party pipelines or other facilities interconnected to our gathering systems become partially or fully unavailable, or if the volumes we gather do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our natural gas gathering systems connect to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third-party pipelines or facilities is not within our control. These pipelines and other facilities may become unavailable because of testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, curtailments of receipt or deliveries due to insufficient capacity or for any other reason. If any of these pipelines or facilities becomes unable to transport natural gas, or if the volumes we gather or transport do not meet the natural gas quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we expand one or more of our gathering systems, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed. Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, the construction of additions to our existing gathering assets may require us to obtain new rights-of-way. We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural gas volumes to our systems or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing or obtaining new rights-of-way increases, our cash flows could be adversely affected.

 

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If we are unable to make acquisitions on economically acceptable terms from Chesapeake or third parties, our future growth would be limited, and any acquisitions we make may reduce, rather than increase, our cash generated from operations on a per unit basis.

Our ability to grow depends, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based, in large part, on our expectation of ongoing divestitures of midstream energy assets by industry participants, including Chesapeake. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase cash distributions to our unitholders. If we are unable to make such accretive acquisitions from Chesapeake or third parties, either because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors, then our future growth and ability to increase distributions will be limited. Furthermore, even if we complete acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.

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

 

   

mistaken assumptions about volumes, revenues and costs, including synergies;

 

   

an inability to secure adequate customer commitments to use the acquired systems or facilities;

 

   

an inability to successfully integrate the assets or businesses we acquire;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

mistaken assumptions about the overall costs of equity or debt;

 

   

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

 

   

unforeseen difficulties operating in new geographic areas; and

 

   

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our right of first offer with respect to certain of Chesapeake’s future midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation is subject to risks and uncertainty, and thus may not enhance our ability to grow our business.

Subject to certain exceptions, our omnibus agreement provides us with a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation. The consummation and timing of any future transactions pursuant to the exercise of our right of first offer with respect to any particular business opportunity will depend upon, among other things, our ability to negotiate definitive agreements with respect to such opportunities and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future transactions pursuant to these rights. Additionally, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Furthermore, for a variety of reasons, we may decide not to exercise these rights when they become available, and our decision will not be subject to unitholder approval. In addition, first offer rights under the omnibus agreement will terminate in certain circumstances. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement—Business Opportunities.”

 

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Our exposure to direct commodity price risk may increase in the future.

We currently generate substantially all of our revenues pursuant to fixed-fee contracts under which we are paid based on the volumes of natural gas that we gather and treat rather than the value of the underlying natural gas. Consequently, our existing operations and cash flows have limited exposure to direct commodity price risk. Although we intend to enter into similar fixed-fee contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. In addition, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity prices risk than our current operations. Future exposure to the volatility of oil and natural gas prices could have a material adverse effect on our business, results of operations and financial condition.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in the midstream energy business, including:

 

   

damage to pipelines and facilities, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, explosions and other natural disasters and acts of terrorism;

 

   

inadvertent damage from construction, farm and utility equipment;

 

   

leaks of natural gas and other hydrocarbons or losses of natural gas as a result of the malfunction of equipment or facilities; and

 

   

other hazards.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. Additionally, we do not have any business interruption/loss of income insurance that would provide coverage in the event of damage to any of our facilities. Although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not adequately insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets for potential environmental liabilities pursuant to our indemnification rights.

 

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We lease substantially all of our compression capacity from a single provider under a long-term fixed price agreement, which could result in disruptions to our operations or our paying above-market prices for our compression requirements in the future.

Compression of our customers’ natural gas is a key component of the services we provide and our largest operating expense. Given that wells produce at progressively lower field pressures as the underlying resources are depleted, field compression is required to maintain sufficient pressure across our gathering systems. We lease substantially all of the compression capacity for our existing gathering systems from MidCon Compression, LLC, a wholly-owned subsidiary of Chesapeake Energy Corporation, under a long-term contract expiring on September 30, 2019 pursuant to which we have agreed to pay specified monthly rates under a fixed-fee structure subject to an annual escalator and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under this agreement, we have granted MidCon Compression the exclusive right to lease and rent compression equipment to us in our Barnett Shale and Mid-Continent acreage dedications through September 30, 2016. Thereafter, we have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon by the parties or to lease compression equipment from unaffiliated third parties. If market rates for compression are less than the specified monthly rates prior to redetermination under the agreement, then the rates we pay for compression under this contract may be higher than the rates we could obtain from a third party. In addition, if MidCon Compression were to default on its obligations under the terms of our agreement, we may not be able to replace such compression capacity in a timely manner or otherwise on terms consistent with our agreement with MidCon Compression or at all. This could result in our failure to meet our contractual obligations to our customers, which could expose us to damages, reduce revenues and have a material adverse effect on our financial condition, results of operation and cash flows. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Compressor Master Rental and Servicing Agreement.”

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and value of our units.

We will be dependent upon the earnings and cash flow generated by our operations in order to meet our debt service obligations and to allow us to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our revolving credit facility restricts our ability to, among other things:

 

   

incur additional debt or issue guarantees;

 

   

incur or permit certain liens to exist;

 

   

make certain investments, acquisitions or other restricted payments;

 

   

modify certain material agreements;

 

   

dispose of assets;

 

   

engage in certain types of transactions with affiliates;

 

   

merge, consolidate or transfer all or substantially all of our assets; and

 

   

prepay certain indebtedness.

Furthermore, our revolving credit facility contains covenants requiring us to maintain a consolidated leverage ratio of not more than 3.50 to 1.00 and an interest coverage ratio of not less than 3.00 to 1.00. Please read “Management’s Discussion of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Liquidity and Capital Resources—Revolving Credit Facility” for definitions of consolidated leverage ratio and interest coverage ratio under our revolving credit facility.

 

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The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in an event of default which could enable our lenders, subject to the terms and conditions of the revolving credit facility, to declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment. The revolving credit facility will also have cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Debt we incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our future level of debt could have important consequences to us, including the following:

 

   

our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including required drilling pad connections and well connections pursuant to our gas gathering agreements as well as acquisitions) or other purposes may be impaired or such financing may not be available on favorable terms;

 

   

our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;

 

   

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

 

   

our flexibility in responding to changing business and economic conditions may be limited.

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

The amount of cash we have available for distribution to holders of our common and subordinated units depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow 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 net losses for financial accounting purposes and may not make cash distributions during periods when we record net income for financial accounting purposes.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may

 

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affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make cash distributions at our intended levels.

Due to our lack of industry and geographic diversification, adverse developments in our existing areas of operation could adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our operations are focused on natural gas gathering, treating and compression services and our assets are principally located in the Barnett Shale region in north-central Texas and the Mid-Continent region in Oklahoma, Texas, Arkansas, New Mexico and Kansas. As a result, our financial condition, results of operations and cash flows depend upon the demand for our services in these regions. Due to our lack of diversification in industry type and geographic location, adverse developments in our current segment of the midstream industry or our existing areas of operation could have a significantly greater impact on our financial condition, results of operations and cash flows than if our operations were more diversified. In particular, a significant portion of our operations and growth strategy are concentrated in the Barnett Shale region, which could disproportionately expose us to operational and regulatory risk in that area.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenues.

An increasing percentage of our customers’ oil and gas production is being developed from unconventional sources, such as deep gas shales. These reservoirs require hydraulic fracturing completion processes to release the gas from the rock so it can flow through casing to the surface. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process, and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenues and results of operations.

We may incur significant costs and liabilities in complying with, or as a result of a failure to comply with, new or existing environmental laws and regulations, and changes in environmental laws or regulations could adversely impact our customers’ production and operations, which could have a material adverse effect on our results of operations and cash flows.

Our natural gas gathering, treating and compression operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws and regulations may impose numerous obligations that are applicable to our operations, including obtaining permits to conduct regulated activities, incurring capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and imposing substantial liabilities and remedial obligations relating to pollution or emissions that may result from our operations. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly actions. Failure to comply with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues.

 

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Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact our customers’ production and operations. For example, the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas have been evaluating possible additional regulation of air emissions in the Barnett Shale area, in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions against the regulated community. Additionally, the EPA has recently entered into a settlement that requires it to consider strengthening revisions to regulations under the Clean Air Act, including the New Source Performance Standards, Maximum Achievable Control Technology standards and residual risk standards, affecting a wide array of air emission sources in the natural gas industry. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our customers’ production, which could have a material adverse effect on our results of operations and cash flows.

There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry practices, our handling of hydrocarbon wastes and air emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass and facilities where our wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. We may not be able to recover all or any of these costs from insurance. Please read “Business—Environmental Matters” for more information.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.

On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other “greenhouse gases” present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. In late September 2009, the EPA had proposed two sets of regulations in anticipation of finalizing its findings that would require a reduction in emissions of greenhouse gases from motor vehicles that could also lead to the imposition of greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the U.S. beginning in 2011 for emissions occurring in 2010. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of greenhouse gases from, our equipment and operations could require us to incur additional costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the natural gas we gather, treat or otherwise handle in connection with our services.

Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or ACESA, which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of “greenhouse gases”, including carbon dioxide and methane. ACESA would require a 17 percent reduction in greenhouse gas emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of

 

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tradable emissions allowances to certain major sources of greenhouse gas emissions so that such sources could continue to emit greenhouse gases into the atmosphere. These allowances would be expected to significantly escalate in cost over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic greenhouse gas emissions and the Obama Administration has indicated its support of legislation to reduce greenhouse gas emissions through an emission allowance system. Although it is not possible at this time to predict when the Senate may act on climate change legislation or how any bill passed by the Senate would be reconciled with ACESA, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions could require us to incur increased operating costs and could adversely affect demand for the natural gas we gather, treat or otherwise handle in connection with our services.

The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of greenhouse gases could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines or other facilities, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for natural gas, resulting in a decrease in demand for our services.

If our assets became subject to regulation by FERC or regulations of state and local agencies were to change, our financial condition, results of operations and cash flows could be materially and adversely affected.

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act. Although FERC has not made any formal determinations respecting any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, not subject to FERC jurisdiction. However, FERC regulation still affects our gathering and compression business. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by the FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. We cannot predict what new or different regulations federal and state regulatory agencies may adopt, or what effect subsequent regulations may have on our activities. Such regulations may have a material adverse effect on our financial condition, results of operations and cash flows.

 

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If our omnibus agreement with Chesapeake is terminated, or if Chesapeake fails to provide us with adequate services, we will have to obtain those services internally or through third-party arrangements.

We will depend on Chesapeake to provide us certain general and administrative services pursuant to our omnibus agreement. The initial term of the provision of general and administrative services by Chesapeake under the omnibus agreement will continue until December 31, 2011 and will extend for additional twelve-month periods unless we or Chesapeake provides 180 days’ prior written notice of termination, subject to certain conditions and limitations. Notwithstanding the foregoing, we have the right to unilaterally extend the provision by Chesapeake of the general and administrative services through June 30, 2012. Though Chesapeake will agree to perform such services using no less than a reasonable level of care in accordance with industry standards, if Chesapeake fails to provide us adequate services, or if our omnibus agreement is terminated for any reason, we will have to obtain these services internally or through third-party arrangements which may result in increased costs to us.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Prior to this offering, we have not been required to file reports with the SEC. Upon the completion of this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002, which we refer to as Section 404. For example, Section 404 will require us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting. We must comply with Section 404 for our fiscal year ending December 31, 2011. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, indirectly own and control our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

Following this offering, Chesapeake Midstream Ventures, which is owned and controlled by Chesapeake and GIP, will own and control our general partner and will appoint all of the officers and directors of our general partner, some of whom will also be officers and directors of Chesapeake, GIP and/or Chesapeake Midstream Ventures. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owner, Chesapeake Midstream Ventures. Conflicts of interest will arise between Chesapeake, GIP, Chesapeake Midstream Ventures and our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor

 

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its own interests and the interests of Chesapeake, GIP and/or Chesapeake Midstream Ventures over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 

   

Neither our partnership agreement nor any other agreement requires Chesapeake, GIP or Chesapeake Midstream Ventures to pursue a business strategy that favors us.

 

   

Our general partner is allowed to take into account the interests of parties other than us, such as Chesapeake, GIP or Chesapeake Midstream Ventures, in resolving conflicts of interest.

 

   

The chief executive officer of our general partner will also devote significant time to the business of Chesapeake and will be compensated by Chesapeake accordingly.

 

   

Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

 

   

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

 

   

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

 

   

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

 

   

Our general partner determines which costs incurred by it are reimbursable by us.

 

   

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period.

 

   

Our partnership agreement permits us to classify up to $             million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights.

 

   

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

 

   

Our general partner intends to limit its liability regarding our contractual and other obligations.

 

   

Disputes may arise under our gas gathering agreement with Chesapeake, including with respect to fee redeterminations or the determination of amounts payable as liquidated damages upon Chesapeake’s failure, if any, to meet its minimum volume commitments under the agreement.

 

   

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

 

   

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

 

   

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

   

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Please read “Conflicts of Interest and Fiduciary Duties.”

 

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Cost reimbursements due to Chesapeake and our general partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to you. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making distributions on our common units, pursuant to our omnibus agreement, employee secondment agreement and shared services agreement, we will reimburse Chesapeake and its affiliates for certain expenses they incur on our behalf. In addition, in accordance with our partnership agreement, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursements to Chesapeake, our general partner and its affiliates will reduce the amount of cash otherwise available for distribution to our unitholders.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

 

   

how to allocate business opportunities among us and its affiliates;

 

   

whether to exercise its limited call right;

 

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how to exercise its voting rights with respect to the units it owns;

 

   

whether to exercise its registration rights;

 

   

whether to elect to reset target distribution levels; and

 

   

whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read “Conflicts of Interest and Fiduciary Duties—Fiduciary Duties.”

Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

 

   

provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is 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 imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

   

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of our partnership;

 

   

provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, 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; and

 

   

provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

 

  (a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

 

  (b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

 

  (c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

  (d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

 

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Our general partner may elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner units to our general partner in connection with resetting the target distribution levels. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner will initially be comprised of seven members, two of whom will be designated by Chesapeake, two of whom will be designated by GIP and three of whom will be independent. Chesapeake Midstream Ventures is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including our three independent directors. If the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

The unitholders initially will be unable to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of this offering to be able to prevent

 

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its removal. The vote of the holders of at least 66  2 / 3 % of all outstanding limited partner units voting together as a single class is required to remove our general partner. Following the closing of this offering, Chesapeake and GIP will own an aggregate of     % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual fraud, gross negligence or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholder’s dissatisfaction with our general partner’s performance in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Chesapeake Midstream Ventures to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

Our general partner will be jointly owned and controlled indirectly by Chesapeake and GIP. As a result, there is a possibility of deadlocks occurring with respect to important governance or other business decisions affecting us to be made by our general partner, which could adversely affect our business.

Our general partner has sole responsibility for conducting our business and for managing our operations and will be controlled by its sole member, Chesapeake Midstream Ventures. Following this offering, Chesapeake and GIP will each directly own a 50% membership interest in, and will jointly control, Chesapeake Midstream Ventures. Chesapeake Midstream Ventures will have the right to appoint our general partner’s entire board of directors, including our three independent directors. We expect that conflicts will arise in the future between Chesapeake, on the one hand, and GIP, on the other hand, with regard to our governance, business and operations. Notwithstanding applicable dispute resolution provisions, important governance or other business decisions could be delayed as a result of a deadlock between Chesapeake and GIP, which could adversely affect our business.

You will experience immediate and substantial dilution in pro forma net tangible book value of $             per common unit.

The estimated initial public offering price of $             per common unit exceeds our pro forma net tangible book value of $             per common unit. Based on the estimated initial public offering price of $             per

 

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common unit, you will incur immediate and substantial dilution of $             per common unit. This dilution results primarily because the assets contributed by our general partner and its affiliates are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read “Dilution.”

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

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

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

 

   

because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

 

   

the ratio of taxable income to distributions may increase;

 

   

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

 

   

the market price of the common units may decline.

Chesapeake and GIP may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

After the sale of the common units offered by this prospectus, Chesapeake and GIP will hold an aggregate of              common units and              subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide each of Chesapeake and GIP with certain registration rights. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Registration Rights Agreement.” The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return or a negative return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, Chesapeake and GIP will own an aggregate of approximately     % of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (other than upon the conversion of the subordinated units), Chesapeake and GIP will own an aggregate of approximately     % of our outstanding common units. For additional information about this right, please read “The Partnership Agreement—Limited Call Right.”

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states.

 

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The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 

   

we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

   

your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

For a discussion of the implications of the limitations of liability on a unitholder, please read “The Partnership Agreement—Limited Liability.”

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

Prior to this offering, there has been no public market for our common units. After this offering, there will be only              publicly traded common units. In addition, Chesapeake and GIP will own an aggregate of              common and              subordinated units, representing an aggregate     % limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The initial public offering price for the common units will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of the common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by many factors, some of which are beyond our control, including:

 

   

our quarterly distributions;

 

   

our quarterly or annual earnings or those of other companies in our industry;

 

   

announcements by us or our competitors of significant contracts or acquisitions;

 

   

changes in accounting standards, policies, guidance, interpretations or principles;

 

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general economic conditions;

 

   

the failure of securities analysts to cover our common units after this offering or changes in financial estimates by analysts;

 

   

future sales of our common units; and

 

   

other factors described in these “Risk Factors.”

We will incur increased costs as a result of being a publicly traded partnership.

We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the New York Stock Exchange, or the NYSE, have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and to possibly result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. We have included $2.0 million of estimated incremental costs per year associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate. These costs are not subject to the volumetric-based cap in the omnibus agreement applicable to general and administrative expenses allocable to us by Chesapeake.

Tax Risks to Common Unitholders

In addition to reading the following risk factors, you should read “Material Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution to you would be substantially reduced.

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

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a

 

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corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to you.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we will be required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any such taxes may substantially reduce the cash available for distribution to you and, therefore, negatively impact the value of an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation for state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the currently proposed legislation would not appear to affect our tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with some or all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some

 

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cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized may include a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. Please read “Material Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

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

Investment in common units by tax-exempt entities, such as 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 that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

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

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read “Material Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we adopted.

We will 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. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will 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. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the

 

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allocation of items of income, gain, loss and deduction among our unitholders. Please read “Material Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees.”

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, he 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, he 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. Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, 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.

We will adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our 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 from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination

 

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occurred. Please read “Material Tax Consequences—Disposition of Common Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

In addition to federal income taxes, you will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions. You will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We will initially own assets and conduct business in Arkansas, Kansas, New Mexico, Oklahoma and Texas. Each of these states, other than Texas, currently imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

 

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USE OF PROCEEDS

We expect to receive net proceeds from the issuance and sale of              common units offered by this prospectus of approximately $             million, after deducting underwriting discounts and commissions, structuring fees and offering expenses. We intend to use these proceeds to repay approximately $             million of borrowings outstanding under our revolving credit facility, to fund future capital expenditures and working capital, and for other general partnership purposes, including acquisitions, if any.

If the underwriters exercise their option to purchase additional common units, we will use the net proceeds therefrom in the same manner as described above. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to              common units, representing an aggregate     % limited partner interest in us.

Our estimates assume an initial public offering price of $             per common unit and no exercise of the underwriters’ option to purchase additional common units. An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts and commissions, structuring fees and offering expenses, to increase or decrease by $             million.

At February 11, 2010, an aggregate of approximately $32 million of borrowings were outstanding under our revolving credit facility. The weighted average interest rate on borrowings under our revolving credit facility was 4.39% at February 11, 2010. Our revolving credit facility matures on September 30, 2012. Borrowings under our revolving credit facility have been used primarily to fund capital expenditures.

The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Affiliates of Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are lenders under our revolving credit facility and will, in that respect, receive a portion of the proceeds from this offering through the repayment of borrowings outstanding under our revolving credit facility. Please read “Underwriting.”

 

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CAPITALIZATION

The following table shows:

 

   

the historical cash and cash equivalents and capitalization of our Predecessor as of September 30, 2009;

 

   

our pro forma capitalization as of September 30, 2009, giving effect to the contribution by Chesapeake and GIP of a portion of our Predecessor’s assets to us; and

 

   

our pro forma as adjusted capitalization as of September 30, 2009, giving effect to the following adjustments:

 

   

our receipt of net proceeds of $             million from the issuance and sale of common units to the public at an assumed initial public offering price of $             per unit; and

 

   

the application of the net proceeds from this offering of approximately $             million in the manner described in “Use of Proceeds.”

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the unaudited consolidated historical financial statements and pro forma as adjusted financial data and the accompanying notes included elsewhere in this prospectus. You should also read this table in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     As of September 30, 2009
     Predecessor
Historical
   Partnership
Pro Forma
   Pro Forma As
Adjusted (1)
     (In thousands)

Cash and cash equivalents

   $ 156,047    $ 35    $             
                    

Revolving credit facility

   $ 12,173    $ 12,173    $             

Total equity:

        

Partners’ net equity

     2,996,403      1,741,186   

Common units—public (2)(3)

     —        —     

Common units—Chesapeake

     —        —     

Common units—GIP

     —        —     

Subordinated units—Chesapeake

     —        —     

Subordinated units—GIP

     —        —     

General partner units

     —        —     
                    

Total equity

     2,996,403      1,741,186   
                    

Total capitalization

   $ 3,008,576    $ 1,753,359    $             
                    

 

(1) On a pro forma as adjusted basis, as of September 30, 2009, the public would have held              common units, Chesapeake would have held an aggregate of              common units and              subordinated units, GIP would have held an aggregate of              common units and              subordinated units and our general partner would have held              general partner units representing a 2.0% general partner interest in us.
(2) An increase or decrease in the initial public offering price of $1.00 per common unit would cause the public common unitholders’ capital to increase or decrease by $              million.
(3) A 1,000,000 unit increase in the number of common units issued to the public would result in a $             million increase in the public common unitholders’ capital.

 

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DILUTION

Dilution is the amount by which the offering price paid by the purchasers of common units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of September 30, 2009, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $            million, or $             per unit. Net tangible book value excludes $             million of net intangible assets. Purchasers of common units in this offering will experience substantial and immediate dilution in net tangible book value per common unit for financial accounting purposes, as illustrated in the following table:

 

Assumed initial public offering price per common unit

      $             

Net tangible book value per unit before the offering (1)

   $                

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

     
         

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

     

Immediate dilution in tangible net book value per common unit to purchasers in the offering (3)

      $             
         

 

(1) Determined by dividing the number of units (             common units,              subordinated units and              general partner units) to be issued to our general partner and its affiliates, including Chesapeake and GIP, for the contribution of assets and liabilities to Chesapeake Midstream Partners, L.P. into the net tangible book value of the contributed assets and liabilities.
(2) Determined by dividing the total number of units to be outstanding after the offering (             common units,              subordinated units and              general partner units) into our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering.
(3) If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $             and $            , respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by our general partner and its affiliates, including Chesapeake and GIP, and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

 

     Units Acquired     Total Consideration  
     Number    Percent     Amount    Percent  
                (In thousands)  

General partner and affiliates (1)(2)

             $                     

Purchasers in the offering

                    
                        

Total

      100.0   $                 100.0
                        

 

(1) The units acquired by our general partner and its affiliates, including Chesapeake and GIP, consist of              common units,              subordinated units and              general partner units.
(2) The assets contributed by our general partner and its affiliates were recorded at Chesapeake’s historical cost of $1.7 billion in accordance with GAAP. Book value of the consideration provided by our general partner and its affiliates, as of September 30, 2009, equals parent net investment, which was $             million and is not affected by this offering.

 

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our cash distribution policy in conjunction with the factors and assumptions upon which our cash distribution policy is based, which are included under the heading “—Assumptions and Considerations” below. In addition, please read “Forward-Looking Statements” and “Risk Factors” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business. For additional information regarding our historical and pro forma operating results, you should refer to our historical financial statements and pro forma financial data, and the notes thereto, included elsewhere in this prospectus.

General

Rationale for Our Cash Distribution Policy . Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our available cash. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy . There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

 

   

Our cash distribution policy may be subject to restrictions on distributions under our revolving credit facility or other debt agreements entered into in the future. Our revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions to you notwithstanding our stated cash distribution policy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Liquidity and Capital Resources—Revolving Bank Credit Facility.”

 

   

Our general partner will have the authority to establish reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

 

   

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement generally may not be amended during the subordination period without the approval of our public common unitholders. However, our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by Chesapeake and GIP) after the subordination period has ended. At the closing of this offering, Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, will own our general partner and will own an aggregate of approximately     % of our outstanding common and subordinated units.

 

   

Even if our cash distribution policy is not 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 general partner, taking into consideration the terms of our partnership agreement.

 

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Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.

 

   

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expense, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash.”

 

   

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution in order to service or repay our debt or fund expansion capital expenditures.

Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital . Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.

Our Minimum Quarterly Distribution

Upon completion of this offering, the board of directors of our general partner will establish a minimum quarterly distribution of $             per unit per complete quarter, or $             per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending June 30, 2010. This equates to an aggregate cash distribution of $             million per quarter, or $             million per year, based on the number of common, subordinated and general partner units to be outstanding immediately after the completion of this offering. If the underwriters exercise in full their option to purchase additional common units, the ownership interest of the public unitholders will increase to              common units representing an aggregate     % limited partner interest in us and our aggregate cash distribution would be $             million per quarter or $             million per year. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption “—General—Limitations on Cash Distributions and Our Ability to Change Our Distribution Policy.”

Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner’s initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. If the underwriters exercise in full their option to purchase additional common units in this offering, however, our general partner will be issued              general partner units in order to maintain its 2.0% general partner interest and will not be required to make a capital contribution to us.

 

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The table below sets forth the assumed number of outstanding common (assuming no exercise and full exercise of the underwriters’ option to purchase additional common units), subordinated and general partner units upon the closing of this offering and the aggregate distribution amounts payable on such units during the year following the closing of this offering at our minimum quarterly distribution rate of $             per unit per quarter ($             per unit on an annualized basis).

 

   

No Exercise of Underwriters’

Option to Purchase Additional Units

  

Full Exercise of Underwriters’

Option to Purchase Additional Units

   

Number of

Units

  

Distributions

  

Number of

Units

  

Distributions

      

One Quarter

  

Annualized

     

One Quarter

  

Annualized

Publicly held common units

    

$

  

$

     

$

  

$

Common units held by Chesapeake

                

Common units held by GIP

                

Subordinated units held by Chesapeake

                

Subordinated units held by GIP

                

General partner units held by our general partner

                
                            

Total

    

$

  

$

     

$

  

$

                            

The subordination period generally will end if we have earned and paid at least $             on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. If, in respect of any quarter, we have earned and paid at least $             (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner’s 2.0% interest and the related distribution on the incentive distributions rights for the four-quarter period immediately preceding that date, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please read the “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period.”

Our cash distribution policy, as expressed in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15 th of each of February, May, August and November to holders of record on or about the 1 st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of this offering through June 30, 2010 based on the actual length of the period.

 

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In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our minimum quarterly distribution of $             per unit each quarter for the year ending December 31, 2010. In those sections, we present two tables, consisting of:

 

   

“Partnership Unaudited Pro Forma Available Cash,” in which we present the amount of cash we would have had available for distribution on a pro forma basis for our fiscal year ended December 31, 2008 and the twelve months ended September 30, 2009, derived from our unaudited pro forma financial data that are included in this prospectus, as adjusted to give pro forma effect to the offering and the formation transactions; and

 

   

“Partnership Statement of Estimated Adjusted EBITDA,” in which we demonstrate our ability to generate the minimum estimated Adjusted EBITDA necessary for us to pay the minimum quarterly distribution on all units for each quarter in the year ending December 31, 2010.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2008 and the Twelve Months Ended September 30, 2009

If we had completed the transactions contemplated in this prospectus on January 1, 2008, pro forma available cash generated for the year ended December 31, 2008 would have been approximately $87 million. This amount would have been sufficient to pay the minimum quarterly distribution of $             per unit per quarter ($             per unit on an annualized basis) on all of the common units and a cash distribution of $             per unit per quarter ($             per unit on an annualized basis), or approximately     % of the minimum quarterly distribution, on our subordinated units for such period.

If we had completed the transactions contemplated in this prospectus on October 1, 2008, our pro forma available cash generated for the twelve months ended September 30, 2009 would have been approximately $112 million. This amount would have been sufficient to pay the minimum quarterly distribution on all of the common units and a cash distribution of $             per unit per quarter (or $             per unit on an annualized basis), or approximately     % of the minimum quarterly distribution, on our subordinated units for such period.

Unaudited pro forma available cash also includes direct, incremental general and administrative expenses of approximately $2.0 million that we expect to incur as a result of becoming a publicly traded partnership. General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These expenses are not reflected in the historical consolidated financial statements of our Predecessor. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Our pro forma financial data does not give effect to our 20-year gas gathering agreements with Chesapeake or Total or any of the other transaction documents that were originally entered into on September 30, 2009 in connection with the formation of the joint venture between Chesapeake and GIP. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

We based the pro forma adjustments upon currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had the transactions contemplated in this prospectus actually been completed as of the dates indicated. In addition, cash available to pay distributions is primarily a cash accounting concept, while our pro forma financial data have been prepared on an accrual basis. As a result, you should view the amount of pro forma available cash only as a general indication of the amount of cash available to pay distributions that we might have generated had we been formed in earlier periods.

 

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The following table illustrates, on a pro forma basis, for the year ended December 31, 2008 and for the twelve months ended September 30, 2009, the amount of cash that would have been available for distribution to our unitholders, assuming in each case that this offering had been consummated at the beginning of such period and that the underwriters exercised in full their option to purchase additional common units in this offering. Each of the pro forma adjustments presented below is explained in the footnotes to such adjustments.

Partnership Unaudited Pro Forma Available Cash

 

     Year Ended
December 31, 2008
    Twelve Months
Ended

September 30, 2009
 
     (In millions)  

Net Income:

   $ 147.7      $ 1.8   

Add:

    

Depreciation and amortization expense

     39.6        66.0   

Interest expense (1)

     0.4        1.6   

Income tax expense (benefit)

     (68.4     —     

Impairment of property, plant and equipment and other assets

     30.0        120.2   
                

Adjusted EBITDA (2)

   $ 149.3      $ 189.6   

Less:

    

Pro forma cash interest expense (1)

     2.5        2.5   

Estimated maintenance capital expenditures (3)

     60.0        75.0   
                

Pro Forma Available Cash

   $ 86.8      $ 112.1   
                

Pro Forma Cash Distributions

    

Distributions per unit

   $                   $                
                

Distributions to public common unitholders (4)

   $                   $                

Distributions to Chesapeake—common units (4)

    

Distributions to GIP—common units (4)

    

Distributions to Chesapeake—subordinated units (4)

    

Distributions to GIP—subordinated units (4)

    

Distributions to our general partner (4)

    

Total distributions

   $                   $                
                

Shortfall

   $                   $                
                

Percent of minimum quarterly distributions payable to common unitholders

                  

Percent of minimum quarterly distributions payable to subordinated unitholders

                  

 

(1) Interest expense represents the commitment fees that would have been paid by our Predecessor on the credit facility that was in place during the periods presented. Pro forma cash interest expense represents the payment of the commitment fee of 0.50% on our new $500 million revolving credit facility.
(2) Adjusted EBITDA is defined in “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.” For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”
(3) For the year ended December 31, 2008 and the twelve months ended September 30, 2009, our total capital expenditures were $876 million and $452 million, respectively. Historically, we did not make a distinction between maintenance and expansion capital expenditures, however for purposes of the presentation of Partnership Unaudited Pro Forma Available Cash, we have estimated that approximately $60 million and $75 million of these capital expenditures were maintenance capital expenditures for the respective periods. The balance of our capital expenditures for the periods presented were assumed to have been expansion capital expenditures and funded by cash contributions from Chesapeake. We have not included these expansion capital expenditures or the related cash contributions from Chesapeake in our calculation of pro forma available cash.

 

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(4) The table below assumes full exercise of the underwriters’ option to purchase additional common units and sets forth the assumed number of outstanding common and subordinated units upon the closing of this offering and the estimated per common and subordinated unit and aggregate distribution amounts payable on our common and subordinated units, as well as the aggregate distribution amount payable on the 2.0% general partner interest for four quarters at our initial distribution rate of $             per common unit per quarter ($             per common unit on an annualized basis).

 

     Full Exercise of the Underwriters’ Option
to Purchase Additional Units
     Number of
Units
   Distributions
      One Quarter    Annualized

Publicly-held common units

        

Common units held by Chesapeake

        

Subordinated units held by Chesapeake

        

Common units held by GIP

        

Subordinated units held by GIP

        

General partner units held by our general partner

        
              

Total

        
              

Estimated Adjusted EBITDA for Year Ending December 31, 2010

In order to fund the aggregate minimum quarterly distribution on all units for the year ending December 31, 2010 totaling $            , we will need to generate Adjusted EBITDA of at least $             million . For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.” Based on the assumptions described below under “—Assumptions and Considerations,” we believe we will generate the minimum estimated Adjusted EBITDA of $             million for the year ending December 31, 2010. This minimum estimated Adjusted EBITDA should not be viewed as management’s projection of the actual amount of Adjusted EBITDA that we will generate during the year ending December 31, 2010. Furthermore, there is a risk that we will not generate the minimum estimated Adjusted EBITDA for such period. If we fail to generate the minimum estimated Adjusted EBITDA, we would not expect to be able to pay the minimum quarterly distribution on all of our units.

We have not historically made public projections as to future operations, earnings or other results. However, management has prepared the minimum estimated Adjusted EBITDA and related assumptions set forth below to substantiate our belief that we will have sufficient available cash to pay the minimum quarterly distribution to all our unitholders for each quarter in the year ending December 31, 2010. This forecast is a forward-looking statement and should be read together with the historical financial statements and pro forma financial data and the accompanying notes included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” The accompanying prospective financial information 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 the minimum estimated Adjusted EBITDA necessary for us to have sufficient cash available for distribution to pay the minimum quarterly distribution to all unitholders for each quarter in the twelve months ending December 31, 2010. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

The prospective financial information included in this registration statement has been prepared by, and is the responsibility of our management. PricewaterhouseCoopers LLP has neither compiled nor performed any

 

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procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP report included in this registration 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 prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those which would enable us to generate the minimum estimated Adjusted EBITDA.

We are providing the minimum estimated Adjusted EBITDA calculation to supplement our unaudited pro forma financial data and historical consolidated financial statements in support of our belief that we will have sufficient available cash to pay the minimum quarterly distribution on all of our outstanding common and subordinated units for each quarter in the year ending December 31, 2010. Please read below under “—Assumptions and Considerations” for further information as to the assumptions we have made for the financial forecast.

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

 

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Partnership Statement of Estimated Adjusted EBITDA

 

     Twelve Months
Ending

December 31,
2010
     (In millions)

Revenues

   $ 450.8

Operating Expenses

  

Operating expenses

     146.2

General and administrative

     31.8

Depreciation and amortization expense

     88.1
      

Total Operating Expenses

     266.1
      

Operating Income

     184.7

Interest expense

     2.5
      

Net Income

     182.2

Adjustments to reconcile net income to estimated Adjusted EBITDA:

  

Add:

  

Depreciation and amortization expense

     88.1

Interest expense

     2.5
      

Estimated Adjusted EBITDA (1)

     272.8

Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:

  

Less:

  

Cash interest expense

     2.5

Estimated expansion capital expenditures

     252.2

Estimated maintenance capital expenditures

     80.0

Add:

  

Cash on hand to fund expansion capital expenditures

     252.2
      

Estimated Cash Available for Distribution

   $ 190.3
      

Distributions to public common unitholders

   $             

Distributions to Chesapeake—common units

  

Distributions to GIP—common units

  

Distributions to Chesapeake—subordinated units

  

Distributions to GIP—subordinated units

  

Distributions to our general partner

  
      

Total distributions

   $             
      

Excess of cash available for distribution over aggregate annualized minimum annual cash distributions

  

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

  

Estimated Adjusted EBITDA

  

Excess of cash available for distribution over minimum annual cash distributions

  

Minimum estimated Adjusted EBITDA necessary to pay aggregate annualized minimum quarterly distributions

   $             

 

(1) Adjusted EBITDA is defined in “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.” For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

 

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Assumptions and Considerations

Set forth below are the material assumptions that we have made in order to demonstrate our ability to generate the minimum estimated Adjusted EBITDA for the twelve months ending December 31, 2010.

General Considerations

 

   

As discussed further below, substantially all of our revenues and certain of our expenses will be determined by contractual arrangements. These contracts were not in place prior to September 30, 2009, and accordingly, our forecasted results are not directly comparable with historical periods. These contracts include, among others:

 

   

our 20-year gas gathering agreements with our primary customers, Chesapeake and Total, which determine the fees that we receive for the gathering and other midstream services that we provide;

 

   

a long-term compression services agreement pursuant to which we lease compression equipment from a subsidiary of Chesapeake under a fixed-fee structure; and

 

   

our omnibus agreement that will govern our reimbursement of certain general and administrative expenses incurred by Chesapeake on our behalf.

Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

 

   

Because we currently generate substantially all of our revenues pursuant to long-term, fixed-fee contracts that include minimum volume commitments in our Barnett Shale region, we have not made any assumptions regarding future commodity price levels in developing our forecast for the twelve months ending December 31, 2010.

 

   

Although actual throughput will influence whether the amount of cash available for distribution for the twelve months ending December 31, 2010 is above or below our forecast, our minimum volume commitments in the Barnett Shale region serve to mitigate the impact of any deviation from our volume projections. For example, if all other assumptions are held constant, a 5% decline in throughput below forecasted levels distributed proportionately across our systems would result in an approximate $4 million, or 2%, decline in cash available for distribution. A decline in forecasted cash flows greater than $             million would result in our generating less than the minimum cash required to pay distributions on the outstanding units at the initial distribution rate for the forecast period.

Revenue

We estimate that we will generate revenue of $451 million for the twelve months ending December 31, 2010, as compared to pro forma revenues of $356 million and $280 million for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. The significant increase in revenue is primarily attributable to an increase in expected volumes and an increase in gathering rates under our gas gathering agreements with Chesapeake and Total. Approximately 75% of our expected revenue will be generated from our Barnett Shale region and is supported by our minimum volume commitment.

 

   

Volumes. We estimate that we will gather 605 Bcf of natural gas, or 1.7 Bcf per day, for the twelve months ending December 31, 2010 as compared to 548 Bcf, or 1.5 Bcf per day (a 10% increase), and 480 Bcf, or 1.3 Bcf per day (a 26% increase), for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. This significant expected increase in volumes in the forecast period is primarily based on our expectation that Chesapeake will increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth quarter 2009 levels.

 

   

Fees. We estimate that we will receive an average fee of $0.71/Mcf for the twelve months ending December 31, 2010 as compared to $0.65/Mcf and $0.58/Mcf for the twelve months ended

 

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September 30, 2009 and the year ended December 31, 2008, respectively. Our fees are projected to increase in 2010 as a result of a full year under our new gathering contracts with Chesapeake and Total, the embedded annual fee escalators in those contracts, and the anticipated relative growth of our higher fee Barnett Shale volumes relative to our Mid-Continent volumes.

 

   

Minimum Volume Commitment Payment. In our Barnett Shale region, our gas gathering agreements with Chesapeake and Total provide for minimum volume commitments in the aggregate of approximately 418 Bcf, or approximately 1.1 Bcf per day, for the twelve months ending December 31, 2010. The minimum volume commitments of 418 Bcf for the twelve months ending December 31, 2010 include approximately 20 Bcf of committed volumes that have been carried forward from the year ended December 31, 2009 pursuant to the one-time allowance under our gas gathering agreements to carry forward up to 10% of the minimum volume commitments for the year ended December 31, 2009. Generally, if actual volumes are lower than the minimum volume commitment, as adjusted in certain instances, for any year (or six month period in the case of the six months ending June 30, 2019) after and including the year ending December 31, 2010 through June 30, 2019, Chesapeake or Total, as applicable, are required to make a cash payment to us equal to their respective share of the shortfall in volumes multiplied by the contracted fees charged under our gas gathering agreements at the end of the year in which the shortfall occurred. Our forecast assumes that we recognize revenue of $20 million during the twelve months ending December 31, 2010 as a result of projected volumes being less than the minimum volume commitments. Of this $20 million, approximately $17 million is attributable to the one-time carryforward described above. We anticipate that this shortfall will be settled in cash in early 2011. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

 

   

Fee Redetermination. The fees for service on the Mid-Continent gathering systems are automatically subject to redetermination on an annual basis for the term of the agreement. The Mid-Continent fees we are assuming for the twelve months ending December 31, 2010 reflect the fact that we agreed with Chesapeake not to undertake a fee redetermination for 2010. Our gas gathering agreements do not provide for a fee redetermination within our Barnett Shale region during the forecast period. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

Operating Expenses

We estimate that we will incur operating expense of $146 million for the twelve months ending December 31, 2010 as compared to $147 million and $118 million for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. Our operating expense is comprised of field operating costs (which include labor, treating chemicals and measurement services, among other items), compression expense, ad valorem and Texas franchise taxes and other operating costs. For the forecast period, we expect field operating costs and compression expense to account for approximately 54% and 38% of our operating expenses, respectively.

The $1 million decrease for the forecast period relative to the twelve months ended September 30, 2009 results from our expectation that an increase in certain of our operating expenses will be more than offset by a decrease in other of our operating expenses, primarily related to the capitalization of certain labor costs related to the construction of our systems. We expect increased expenses to primarily result from additional compression and other operating expenses necessary to accommodate increased throughput and continued expansion of our gathering systems as well as additional direct costs that we expect to incur in order to operate as a standalone entity.

General and Administrative Expenses

Our general and administrative expense will primarily consist of direct general and administrative expenses incurred by us, payments we make to Chesapeake in exchange for the provision of a portion of our general and administrative services as well as $2 million of expenses we expect to incur as a result of becoming a publicly

 

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traded partnership. Under the omnibus agreement, our reimbursement to Chesapeake of certain general and administrative expenses in any given month will be subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, subject to an annual escalation. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.” General and administrative expenses related to being a publicly traded partnership include expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs and director compensation.

We expect our general and administrative expense to total $32 million for the twelve months ending December 31, 2010 as compared to $21 million and $13 million for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. Of this increase, the substantial majority is attributable to the establishment of our independent management team and the incremental expenses that we expect to incur as a result of being a publicly traded partnership. These expenses are not reflected in the historical consolidated financial statements of our Predecessor but are reflected in our pro forma financial data (other than management team expenses). Included in our estimate is an assumed $18 million general and administrative expense reimbursement to Chesapeake under our omnibus agreement, which has been estimated by applying the unadjusted cap of $0.03 per Mcf.

Depreciation and Amortization Expense

We estimate that depreciation and amortization expense for the twelve months ending December 31, 2010 will be $88 million as compared to $66 million and $40 million for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. Estimated depreciation and amortization expense reflects management’s estimates, which are based on consistent average depreciable asset lives and depreciation methodologies. The increase in depreciation and amortization is attributable to an expected increase in capital investments in our assets.

Capital Expenditures

We estimate that total capital expenditures for the twelve months ending December 31, 2010 will be $332 million as compared to $452 million and $876 million for the twelve months ended September 30, 2009 and the year ended December 31, 2008, respectively. Capital expenditures in the prior periods were higher due to the significant build-out of assets in these periods.

 

   

Maintenance Capital Expenditures. Historically, we did not make a distinction between maintenance and expansion capital expenditures. Our estimate of $80 million for maintenance capital expenditures for the twelve months ending December 31, 2010 reflects our management’s judgment of the amount of capital that will be needed annually to maintain the current throughput across our systems and the current operating capacity of our assets for the long-term. The types of maintenance capital expenditures that we expect to incur include expenditures to connect additional wells to maintain current volumes and expenditures to replace system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives.

 

   

Expansion Capital Expenditures. We estimate that our expansion capital expenditures for the twelve months ending December 31, 2010 will total $252 million. Approximately 75% of these expenditures relate to expected activity in our Barnett Shale region, where Chesapeake has indicated that it will increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth quarter 2009 levels. We expect the balance of our expansion capital to be spent in our Mid-Continent region, primarily related to increasing producer activity in the Colony Granite Wash and Texas Panhandle Granite Wash plays and the Permian Basin.

 

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Financing

 

   

Cash. At the closing of this offering and after using a portion of the net proceeds of this offering to repay borrowings outstanding under our revolving credit facility as described in “Use of Proceeds,” we expect to have no outstanding indebtedness and cash on hand of $                 million, which we believe will be sufficient to fund our anticipated expansion capital expenditures during the forecast period.

 

   

Indebtedness. For purposes of our forecast for the twelve months ending December 31, 2010, we have assumed that the closing of this offering takes place on January 1, 2010. Accordingly, we have assumed that our $500 million revolving credit facility remains undrawn during the forecast period and that our expansion capital expenditures are financed with cash on hand.

 

   

Interest Expense. Because we are assuming that our revolving credit facility remains undrawn during the forecast period, our cash interest expense for the twelve months ending December 31, 2010 results solely from the commitment fee of 0.50% that we expect to pay on the undrawn portion of our revolving credit facility. We have assumed no interest income with respect to the cash that we maintain on our balance sheet during the forecast period.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending December 31, 2010 is based on the following significant assumptions related to regulatory, industry and economic factors:

 

   

There will not be any new federal, state or local regulation of the midstream energy sector, or any new interpretation of existing regulations, that will be materially adverse to our business.

 

   

There will not be any major adverse change in the midstream energy sector or in market, insurance or general economic conditions.

 

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions of Available Cash

General . Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2010, we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of the offering through June 30, 2010.

Definition of Available Cash . Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

 

   

less , the amount of cash reserves established by our general partner to:

 

   

provide for the proper conduct of our business;

 

   

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

 

   

provide funds for distributions to our unitholders for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for subordinated units unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages for the next four quarters);

 

   

plus , if our general partner so determines, all or a 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 generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months.

Intent to Distribute the Minimum Quarterly Distribution . We intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $             per unit, or $             on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

General Partner Interest and Incentive Distribution Rights . Initially, our general partner will be entitled to 2.0% of all quarterly distributions that we make after inception and prior to our liquidation. The general partner interest will be represented by              general partner units. General partner units are not deemed outstanding for purposes of voting and such units represent a non-voting general partner interest. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner’s initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. If, however, the underwriters’ option is exercised in this offering and additional common units are issued, our general partner will maintain its initial 2.0% interest and will not be required to make a capital contribution to us.

 

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Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $             per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on limited partner units that it owns.

Operating Surplus and Capital Surplus

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

Operating Surplus . Operating surplus consists of:

 

   

$              million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:

 

   

borrowings that are not working capital borrowings;

 

   

sales of equity and debt securities;

 

   

sales or other dispositions of assets outside the ordinary course of business;

 

   

capital contributions received; and

 

   

corporate reorganizations or restructurings;

provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

 

   

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

 

   

cash distributions paid on equity issued to finance all or a portion of the construction, acquisition or improvement or replacement of a capital asset (such as equipment or facilities) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service or the date that it is abandoned or disposed of; less

 

   

all of our operating expenditures (as defined below) after the closing of this offering; less

 

   

the amount of cash reserves established by our 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.

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

 

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operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash distributions we receive from non-operating sources.

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 further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

We define operating expenditures in the partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner, reimbursement of expenses to Chesapeake for services pursuant to the omnibus agreement, for services pursuant to our shared services agreement or for personnel provided to us under the employee secondment agreement, payments made under our gas compressor master rental and servicing agreement, payments made under interest rate hedge agreements or commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures (as discussed in further detail below), provided that operating expenditures will not include:

 

   

repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus above when such 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 (as discussed in further detail below);

 

   

investment capital expenditures;

 

   

payment of transaction expenses relating to interim capital transactions;

 

   

distributions to our partners (including distributions in respect of our incentive distribution rights); or

 

   

repurchases of equity interests except to fund obligations under long-term incentive plans.

Capital Surplus . Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:

 

   

borrowings other than working capital borrowings;

 

   

sales of our equity and debt securities; and

 

   

sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

Characterization of Cash Distributions . Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter

 

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immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.

Capital Expenditures

For purposes of determining operating surplus, maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity or operating income, and expansion capital expenditures are those capital expenditures that we expect will expand our operating capacity or operating income over the long-term. The primary component of maintenance capital expenditures is well connection expenditures required to replace expected reductions in natural gas gathering volumes handled by our facilities. Other components of maintenance capital expenditures include expenditures for routine equipment and pipeline maintenance or replacement due to obsolescence. Maintenance capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, improvement or replacement of an asset that is paid in respect of the period that begins when we enter into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that any such replacement asset commences commercial service or the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

Because our maintenance capital expenditures can be irregular, the amount of our actual maintenance capital expenditures may differ substantially from period to period, which could cause similar fluctuations in the amounts of operating surplus, adjusted operating surplus and cash available for distribution to our unitholders if we subtracted actual maintenance capital expenditures from operating surplus.

Our partnership agreement will require that an estimate of the average quarterly maintenance capital expenditures necessary to maintain our operating capacity or operating income 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 for those periods will be subject to review and change by our general partner at least once a year, provided that any change is approved by our conflicts committee. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of our maintenance capital expenditures, such as a major acquisition or the introduction of new governmental regulations that will impact our business. For purposes of calculating operating surplus, any adjustment to this estimate will be prospective only. For a discussion of the amounts we have allocated toward estimated maintenance capital expenditures, please read “Our Cash Distribution Policy and Restrictions on Distributions.”

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 initial quarterly distribution to be paid on all the units for the quarter and subsequent quarters;

 

   

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

 

   

it will be more difficult for us to raise our distribution above the minimum quarterly distribution and pay incentive distributions on the incentive distribution rights held by our general partner.

Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional pipeline or treating capacity or new compression capacity, to the extent such capital expenditures are expected to expand our long-term operating capacity or

 

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operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction of such capital improvement during the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the date any such capital improvement commences commercial 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.

As described below, neither investment capital expenditures nor expansion capital expenditures are subtracted from operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all or a portion of the construction, replacement or improvement of a capital asset (such as gathering pipelines or treating facilities) during the period that begins when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial 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).

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 facilities that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

Capital expenditures that are made in part for maintenance capital purposes, investment capital and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner, with the concurrence of our conflicts committee.

Subordination Period

General . Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $             per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

Subordination Period . Except as described below, the subordination period will begin on the closing date of this offering and expire the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending June 30, 2013, if each of the following has occurred:

 

   

distributions of available cash from operating surplus on each of the outstanding common, subordinated and general partner units equaled or exceeded the minimum quarterly distribution for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

 

   

the “adjusted operating surplus” (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of

 

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the minimum quarterly distributions on all of the outstanding common, subordinated and general partner units during those periods on a fully diluted weighted average basis during those periods; and

 

   

there are no arrearages in payment of the minimum quarterly distribution on the common units.

Early Termination of Subordination Period . Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day after the distribution to unitholders in respect of any quarter, if each of the following has occurred:

 

   

distributions of available cash from operating surplus on each of the outstanding common, subordinated and general partner units equaled or exceeded $             (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

 

   

the “adjusted operating surplus” (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of $             (150.0% of the annualized minimum quarterly distribution) on each of the outstanding common, subordinated and general partner units on a fully diluted weighted average basis and the related distribution on the incentive distribution rights; and

 

   

there are no arrearages in payment of the minimum quarterly distributions on the common units.

Expiration of the Subordination Period . When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions of available cash. In addition, if the unitholders remove our general partner other than for cause and no units held by our general partner and its affiliates are voted in favor of such removal:

 

   

the subordination period will end and each subordinated unit will immediately convert into one common unit;

 

   

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

   

our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests, in each case based on the fair market value of its general partner units and its incentive distribution rights.

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

 

   

operating surplus generated with respect to that period (excluding any amounts attributable to the items described in the first bullet point under “—Operating Surplus and Capital Surplus—Operating Surplus” above); less

 

   

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

 

   

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

 

   

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

 

   

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

Cash payments by any of our customers, including Chesapeake and Total, to settle a shortfall associated with any minimum volume commitment under a gas gathering agreement will be operating surplus in the quarter in which they are actually received. An estimated, prorated amount of such payments, however, may be included in adjusted operating surplus by our general partner in the manner generally described below. As described

 

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elsewhere in this prospectus, the cash settlement of any shortfall in actual volumes associated with the minimum volume commitments of Chesapeake and Total will be settled in the year following the calendar year to which such volume commitments relate. In order to accommodate the rolling-four quarter test associated with expiration of the subordination period (relative to any after the period payment associated with a shortfall in any minimum volume commitment), to the extent that the actual volumes (associated with a minimum volume commitment) in a particular quarter or quarters are less than the prorated minimum volume commitment amount for such period, our general partner may add to adjusted operating surplus for such period an amount equal to such shortfall in actual volumes, multiplied by the then applicable gathering rate. The quarterly shortfall payment estimate would be adjusted each subsequent quarter based on the level of actual volumes for such subsequent quarter and the preceding quarters of the period that remain subject to a minimum volume commitment (as compared to the prorated volume commitment for such period). If the estimated amount of shortfall payments used by our general partner to increase adjusted operating surplus in prior quarters is more than any shortfall amount actually paid for a minimum volume commitment period as finally determined, and subordinated units remain outstanding, then adjusted operating surplus shall be adjusted in each such quarter to give effect to the actual amount of the payment as if it had been received in such quarter to cover the shortfall in such quarter.

Distributions of Available Cash From Operating Surplus During the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

 

   

first , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

   

second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

 

   

third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until we distribute for each subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter , in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Distributions of Available Cash From Operating Surplus After the Subordination Period

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

 

   

first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

 

   

thereafter , in the manner described in “—General Partner Interest and Incentive Distribution Rights” below.

The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

 

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General Partner Interest and Incentive Distribution Rights

Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

If for any quarter:

 

   

we have distributed available cash from operating surplus to the common and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

 

   

we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

 

   

first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives a total of $             per unit for that quarter (the “first target distribution”);

 

   

second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives a total of $              per unit for that quarter (the “second target distribution”);

 

   

third , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives a total of $              per unit for that quarter (the “third target distribution”); and

 

   

thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

 

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Percentage Allocations of Available Cash From Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total quarterly distribution per unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest, assume our general partner has contributed any additional capital to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

 

     Total quarterly distribution
per unit
   Marginal percentage interest in distributions  
      Unitholders     General partner  

Minimum Quarterly Distribution

     $                98.0   2.0

First Target Distribution

     up to $                98.0   2.0

Second Target Distribution

   above $              up to $                85.0   15.0

Third Target Distribution

   above $ up to $                75.0   25.0

Thereafter

     above $                50.0   50.0

General Partner’s Right to Reset Incentive Distribution Levels

Our general partner, as the holder of our incentive distribution rights, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner’s right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units and general partner units based on a predetermined formula described below that takes into account the “cash parity” value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. Our general partner will be issued the number of general partner units necessary to maintain our general partner’s interest in us immediately prior to the reset election.

The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended

 

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immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

 

   

first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until each unitholder receives an amount per unit equal to 115.0% of the reset minimum quarterly distribution for that quarter;

 

   

second , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

 

   

third , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

 

   

thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

 

    Quarterly distribution
per unit prior to reset
  Marginal percentage interest in
distribution
    Quarterly distribution per
unit following hypothetical

reset
    Unitholders     General partner    

Minimum Quarterly Distribution

    $               98.0   2.0     $                

First Target Distribution

    up to $               98.0   2.0     up to $              (1)

Second Target Distribution

  above $              up to $               85.0   15.0   above $               (1)  up to $              (2)

Third Target Distribution

  above $              up to $               75.0   25.0   above $               (2)  up to $              (3)

Thereafter

    above $               50.0   50.0     above $              (3)

 

(1) This amount is 115.0% of the hypothetical reset minimum quarterly distribution.
(2) This amount is 125.0% of the hypothetical reset minimum quarterly distribution.
(3) This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

 

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The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of incentive distribution rights, or IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be              common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $              for the two quarters prior to the reset.

 

    Quarterly
distribution per
unit prior to
reset
  Cash
distributions
to common
unitholders
prior to reset
  Cash distributions to general partner prior to
reset
  Total
distributions
      Common
Units
  2.0% general
partner
interest
  Incentive
distribution
rights
  Total  

Minimum Quarterly Distribution

  $               $               $—       —     $               $            

First Target Distribution

  up to $                 —       —      

Second Target Distribution

  above $            

up to $            

    —          

Third Target Distribution

  above $            

up to $            

    —          

Thereafter

  above $                 —          
                 
    $               $—         $               $            
                         

The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of IDRs, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be              common units outstanding, our general partner’s 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its IDRs for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

 

    Quarterly
distribution per
unit prior to
reset
  Cash
distributions
to common
unitholders
prior to reset
  Cash distributions to general partner prior
to reset
  Total
distributions
      Common
Units
  2.0% general
partner
interest
  Incentive
distribution
rights
  Total  

Minimum Quarterly Distribution

  $               $               $               $               $—     $               $            

First Target Distribution

  up to $               —     —     —     —     —     —  

Second Target Distribution

  above $            

up to $            

  —     —     —     —     —     —  

Third Target Distribution

  above $            

up to $            

  —     —     —     —     —     —  

Thereafter

  above $               —     —     —     —     —     —  
                         
    $               $               $               $—     $               $            
                         

Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

 

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Distributions From Capital Surplus

How Distributions from Capital Surplus Will Be Made . Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

 

   

first , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price;

 

   

second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and

 

   

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

The preceding paragraph assumes that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

Effect of a Distribution from Capital Surplus . Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered initial unit price.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels will be reduced to zero. Our partnership agreement specifies that we then make all future distributions from operating surplus, with 50.0% being paid to the holders of units and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

 

   

the minimum quarterly distribution;

 

   

the target distribution levels;

 

   

the unrecovered initial unit price; and

 

   

the number of common units into which a subordinated unit is convertible.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be convertible into two common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

 

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In addition, if legislation is enacted or if existing law is modified or interpreted by a governmental taxing authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter and the denominator of which is the sum of available cash for that quarter plus our general partner’s estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Distributions of Cash Upon Liquidation

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

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

Manner of Adjustments for Gain . The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

 

   

first , to our general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

 

   

second , 98.0% to the common unitholders, pro rata, and 2.0% to our general partner, until the capital account for each common unit is equal to the sum of: (i) the unrecovered initial unit price; (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and (iii) any unpaid arrearages in payment of the minimum quarterly distribution;

 

   

third , 98.0% to the subordinated unitholders, pro rata, and 2.0% to our general partner, until the capital account for each subordinated unit is equal to the sum of: (i) the unrecovered initial unit price; and (ii) the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

 

   

fourth , 98.0% to all unitholders, pro rata, and 2.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98.0% to the unitholders, pro rata, and 2.0% to our general partner, for each quarter of our existence;

 

   

fifth , 85.0% to all unitholders, pro rata, and 15.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the second target distribution per

 

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unit over the first target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner for each quarter of our existence;

 

   

sixth , 75.0% to all unitholders, pro rata, and 25.0% to our general partner, until we allocate under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner for each quarter of our existence; and

 

   

thereafter , 50.0% to all unitholders, pro rata, and 50.0% to our general partner.

The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that clause (iii) of the second bullet point above and all of the third bullet point above will no longer be applicable.

Manner of Adjustments for Losses . If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

 

   

first , 98.0% to holders of subordinated units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the subordinated unitholders have been reduced to zero;

 

   

second , 98.0% to the holders of common units in proportion to the positive balances in their capital accounts and 2.0% to our general partner, until the capital accounts of the common unitholders have been reduced to zero; and

 

   

thereafter , 100.0% to our general partner.

If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

Adjustments to Capital Accounts . Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner 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, our partnership agreement requires that we 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 general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

 

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SELECTED HISTORICAL AND UNAUDITED PRO FORMA FINANCIAL AND OPERATING DATA

The following table shows selected consolidated historical financial and operating data for our Predecessor and pro forma as adjusted financial and operating data for Chesapeake Midstream Partners, L.P. for the periods and as of the dates presented. In connection with this offering, Chesapeake and GIP will contribute to us a portion of the business of our Predecessor consisting of certain assets and operations which have historically been principally engaged in gathering, treating and compressing natural gas for Chesapeake and its working interest partners and are currently held by Chesapeake MLP Operating, L.L.C. The historical financial statements included elsewhere in this prospectus reflect the assets, liabilities and operations of our Predecessor. Since our operations will only represent a portion of the operations of our Predecessor and due to other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting the Comparability of Our Financial Results,” our future results of operations will not be comparable to our Predecessor’s historical results.

Our Predecessor’s selected consolidated historical balance sheet data as of December 31, 2007 and 2008 and selected consolidated historical statement of income and cash flow data for the years ended December 31, 2006, 2007 and 2008 are derived from the audited historical consolidated financial statements of our Predecessor included elsewhere in this prospectus. Our Predecessor’s selected consolidated historical balance sheet data as of December 31, 2005 and 2006 and selected consolidated historical statement of income and statement of cash flow data for the year ended December 31, 2005 are derived from audited historical consolidated financial statements of our Predecessor not included in this prospectus. Our Predecessor’s selected consolidated historical balance sheet, statement of income and statement of cash flow data for the year ended December 31, 2004 is derived from the unaudited historical consolidated financial statements of our Predecessor not included in this prospectus. Our Predecessor’s selected consolidated historical balance sheet data as of September 30, 2009 and selected consolidated historical statement of income and cash flow data for the nine months ended September 30, 2008 and 2009 are derived from the unaudited historical consolidated financial statements of our Predecessor included elsewhere in this prospectus.

Our selected pro forma as adjusted statement of income data for the year ended December 31, 2008 and the nine months ended September 30, 2009 and selected pro forma as adjusted balance sheet data as of September 30, 2009 are derived from the unaudited pro forma financial data of Chesapeake Midstream Development, L.P. included elsewhere in this prospectus. The pro forma adjustments have been prepared as if certain transactions to be effected at the closing of this offering had taken place on September 30, 2009, in the case of the pro forma as adjusted balance sheet, and as of January 1, 2008, in the case of the pro forma as adjusted statements of operations for the year ended December 31, 2008 and for the nine months ended September 30, 2009. These transactions include:

 

   

the contribution by Chesapeake and GIP of a portion of the business of our Predecessor to us (constituting approximately 57% of the total assets of our Predecessor as of September 30, 2009);

 

   

the receipt by the Partnership of net proceeds of $              million from the issuance and sale of common units to the public at an assumed initial public offering price of $              per unit; and

 

   

the application of the net proceeds from this offering of approximately $              million in the manner described in “Use of Proceeds.”

The pro forma as adjusted financial data gives effect to an estimated $2.0 million of additional annual general and administrative expenses we expect to incur as a result of being a publicly traded partnership. The pro forma as adjusted financial data does not give effect to our 20-year gas gathering agreements with Chesapeake or Total or any transaction documents that were originally entered into on September 30, 2009 in connection with the formation of the joint venture between Chesapeake and GIP. Pease read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

 

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The following table includes our Predecessor’s historical and our pro forma Adjusted EBITDA, which have not been prepared in accordance with GAAP. Adjusted EBITDA is presented because it is helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

 

    Predecessor Consolidated     Partnership Pro Forma
as Adjusted
    Year Ended December 31,     Nine Months Ended
September 30,
    Year Ended
December 31,

2008
    Nine Months
Ended
September 30,

2009
    2004     2005     2006     2007     2008     2008     2009      
    (unaudited)                            

(unaudited)

   

(unaudited)

    (In thousands, except per unit and operating data)

Statement of Income Data:

                 

Revenues

  $ 28,613      $ 65,014      $ 100,590      $ 191,931      $ 332,783      $ 234,678      $ 358,921      $ 280,272      $ 275,718

Operating expenses

    6,640        19,612        34,914        77,589        141,803        97,419        146,604        117,860        110,174

General and administrative expense

    2,196        1,804        2,766        6,880        13,362        9,400        22,782        13,060        16,780

Depreciation and amortization expense

    1,555        5,080        9,761        24,505        47,558        31,529        65,477        39,550        52,513
                                                                     

Total operating expenses

    10,391        26,496        47,441        108,974        202,723        138,348        234,863        170,470        179,467
                                                                     

Operating income

    18,222        38,518        53,149        82,957        130,060        96,330        124,058        109,802        96,251

Interest expense

    —          —          —          —          1,871        —          347        411        1,162

(Gain) loss on sale of assets (1)

    —          —          —          —          (5,541     (6,242     44,566        —          13

Other expense (income)

    —          —          —          —          (278     (306     (29     —          25

Impairment of property, plant and equipment and other assets (2)

    —          —          —          —          30,000        —          90,207        30,000        90,207

Income tax expense (benefit) (3)

    6,560        14,444        19,931        31,109        (61,287     (62,986     6,341        (68,351     —  
                                                                     

Net income (loss)

  $ 11,662      $ 24,074      $ 33,218      $ 51,848      $ 165,295      $ 165,864      $ (17,374   $ 147,742      $ 4,844
                                                                     

General partner interest in net income

                 

Common unitholders’ interest in net income

                 

Subordinated unitholders’ interest in net income

                 

Net income per common unit (basic and diluted)

                $                   $             

Net income per subordinated unit (basic and diluted)

                $                   $             

Balance Sheet Data (at period end):

                 

Net property, plant and equipment

  $ 73,445      $ 141,760      $ 381,090      $ 965,801      $ 2,339,473        $ 2,870,547        $ 1,744,973

Total assets

    81,096        154,923        403,141        1,010,112        2,583,765          3,232,840          2,123,148

Revolving credit facility

    —          —          —          —          460,000          12,173          —  

Total equity

    46,771        129,461        325,951        847,421        1,793,269          2,996,403          2,019,186

Cash Flow Data:

                 

Net cash provided by (used in):

                 

Operating activities

  $ 14,474      $ 29,510      $ 55,587      $ 93,948      $ 236,774      $ 134,473      $ 100,748       

Investing activities

    (29,328     (67,128     (218,843     (563,564     (1,384,834     (867,786     (690,994    

Financing activities

    14,853        37,620        163,272        469,622        1,230,059        733,316        664,268       

Other Data:

                 

Adjusted EBITDA (4)

      $ 62,910      $ 107,462      $ 177,896      $ 128,165      $ 189,564      $ 149,352      $ 148,739

Capital expenditures

        218,843        563,564        1,402,449        885,395        756,883       

Operating Data:

                 

Throughput, MMcf/d

    254        512        588        1,018        1,585        1,529        2,089        1,315        1,532

Average rate per Mcf

  $ 0.31      $ 0.35      $ 0.47      $ 0.52      $ 0.58      $ 0.56      $ 0.63      $ 0.58      $ 0.66

 

(1) Our Predecessor recorded a $44.6 million loss on the disposal of certain non-core and non-strategic gathering systems for the nine months ended September 30, 2009 and a $6.2 million gain on the disposal of certain gathering systems sold by Chesapeake in conjunction with an upstream transaction for the nine months ended September 30, 2008.
(2)

Our Predecessor recorded an $86.2 million impairment associated with certain gathering systems located in our Mid-Continent region that are not expected to have future cash flows in excess of the book value of the systems. These systems were subsequently contributed to us during the nine months ended September 30, 2009. Additionally, $4 million of debt issuance costs were expensed

 

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as a result of the amendment of our Predecessor’s $460 million credit facility. During the year ended December 31, 2008, our Predecessor recorded a $30.0 million impairment associated with certain of its treating assets as a result of an expected continued decline in throughput with respect to such assets.

(3) Prior to February 2008, our Predecessor filed a consolidated federal income tax return and state returns as required with Chesapeake. In February 2008, upon and subsequent to contribution of assets to our Predecessor by Chesapeake, our Predecessor and certain of its subsidiaries became a partnership and limited liability companies, respectively, and were subsequently treated as pass through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in our financial statements. As such, our Predecessor has provided for the change in legal structure which occurred in 2008 by recording a $63 million income tax benefit for the nine months ended September 30, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our Predecessor’s remaining taxable entity that was not contributed to us.
(4) Adjusted EBITDA is defined in “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.” For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Summary—Summary Historical and Unaudited Pro Forma Financial and Operating Data—Non-GAAP Financial Measure.”

 

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL

CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with the “Selected Historical and Unaudited Pro Forma Financial and Operating Data” and the accompanying financial statements and related notes included elsewhere in this prospectus. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Please read “Risk Factors” and “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

The historical financial statements included elsewhere in this prospectus reflect the assets, liabilities and operations of our Predecessor. In connection with this offering, a portion of the business historically conducted by our Predecessor is being contributed to us by Chesapeake and GIP. Unless the context otherwise requires, references to “our assets,” “our systems” and similar descriptions of our business and operations relate only to the portion of our Predecessor to be contributed to us at the closing of this offering. Please read “—Chesapeake Midstream Partners, L.P. and Our Predecessor” below. The following discussion analyzes the historical financial condition and results of operations of our Predecessor.

Overview

We are a limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts. Our gathering systems operate in our Barnett Shale region in north-central Texas and our Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service more than 1,500 wells in the core of the prolific Barnett Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. Our systems consist of approximately 2,810 miles of gathering pipelines, servicing over 3,500 natural gas wells. For the nine months ended September 30, 2009, our assets gathered approximately 1.5 Bcf of natural gas per day, ranking us among the largest natural gas gatherers in the U.S.

The results of our operations are primarily driven by the volumes of natural gas we gather, treat and compress across our gathering systems. We currently provide all of our gathering, treating and compression services pursuant to fixed-fee contracts, which limit our direct commodity price exposure, and we generally do not take title to the natural gas we gather. We have entered into 20-year gas gathering agreements with Chesapeake and Total, Chesapeake’s upstream joint venture partner in the Barnett Shale. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to dedicate extensive acreage in our Barnett Shale region and Chesapeake has agreed to dedicate extensive acreage in our Mid-Continent region. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows: (i) 10-year minimum volume commitments in our Barnett Shale region, which mitigate throughput volume variability; (ii) fee redetermination mechanisms in our Barnett Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and (iii) price escalators in our Barnett Shale and Mid-Continent regions, which annually increase our gathering rates.

 

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For further information, please read “—Our Gas Gathering Agreements” and “—Quantitative and Qualitative Disclosures About Market Risk” below as well as “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

Chesapeake Midstream Partners, L.P. and Our Predecessor

In September 2009, Chesapeake and GIP formed a joint venture to own and operate Chesapeake’s midstream assets located in the Barnett Shale and Mid-Continent regions. In connection with the closing of this offering, Chesapeake and GIP will contribute to us the assets of the midstream joint venture in the form of a 100% membership interest in Chesapeake MLP Operating, L.L.C., which owned all of our assets prior to that contribution. From February 2008 until September 2009, our assets were owned by Chesapeake Midstream Development, L.P. and its subsidiaries, which we refer to in this prospectus as our “Predecessor.” Prior to the formation of Chesapeake Midstream Development, L.P. in February 2008, our assets were held in various subsidiaries of Chesapeake Energy Corporation throughout its midstream segment. As it relates to our Predecessor, the following discussion should be interpreted as follows:

 

   

when discussing periods prior to the formation of Chesapeake Midstream Development, L.P. in February 2008, the historical financial condition and results of operations of our Predecessor are those of the assets and operations held in various subsidiaries of Chesapeake throughout its midstream segment; and

 

   

when discussing periods subsequent to the formation of Chesapeake Midstream Development, L.P. in February 2008, the historical financial condition and results of operations of our Predecessor are those of the assets and operations of Chesapeake Midstream Development, L.P. and its subsidiaries, which are the same assets and operations referenced in the preceding bullet.

Our assets and operations differ from the historical assets and operations of our Predecessor. In addition to the gathering systems to be contributed to us at the closing of this offering, our Predecessor owns and operates gathering systems in, among other areas, the three other major U.S. shale plays: the Haynesville Shale in northwestern Louisiana and east Texas; the Fayetteville Shale in central Arkansas; and the Marcellus Shale in Pennsylvania, West Virginia and New York.

On a pro forma basis, our assets constituted approximately 57% of the total assets of our Predecessor as of September 30, 2009. Our assets generally consist of developed midstream infrastructure with a more stable cash flow profile, while our Predecessor’s retained assets are generally less developed. Initial midstream investments in developing areas generally require significant build-out capital expenditures in advance of cash flows from throughput associated with new wells connected to the system. Additionally, substantially all of our revenues are currently derived from gathering, treating and compression services that we provide to Chesapeake and Total pursuant to gas gathering agreements that were entered into, in the case of Chesapeake, concurrently with our Predecessor transferring assets to the joint venture formed by Chesapeake and GIP in September 2009 and, in the case of Total, in February 2010. Such gas gathering agreements include contractual provisions, including minimum volume commitments and increased gathering rates, which were not afforded to our Predecessor. Accordingly, any increase in revenues attributable to such gas gathering agreements are not reflected in the historical financial statements of our Predecessor. For these reasons as well as those outlined in “—Items Impacting the Comparability of Our Financial Results” below, the historical results of operations of our Predecessor presented below may not be indicative of our future results of operations.

Our Gas Gathering Agreements

We are a party to (i) a 20-year gas gathering agreement with certain subsidiaries of Chesapeake Energy Corporation that was entered into in connection with a midstream joint venture transaction between Chesapeake and GIP in September 2009, and (ii) a 20-year gas gathering agreement with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total in January 2010.

 

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Future revenues under our gas gathering agreements will be derived pursuant to terms that will differ between our two main operating regions, our Barnett Shale region and our Mid-Continent region. The following outlines the key economic provisions of our gas gathering agreements by region.

Barnett Shale Region . Under our gas gathering agreements with Chesapeake and Total, we have agreed to provide the following services in our Barnett Shale region for the fees and obligations outlined below:

 

   

Gathering, Treating and Compression Services . We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per Mcf for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems receive our customers’ natural gas, which we refer to as the Barnett Shale fee. Our Barnett Shale fee is subject to an annual rate escalation ranging between 2.0% and 2.5% at the beginning of each year.

 

   

Acreage Dedication . Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within an acreage dedication in our Barnett Shale region. For more detail on the acreage dedication, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement” and “—Gas Gathering Agreements.”

 

   

Minimum Volume Commitments . Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75% of the aggregate minimum volume commitments will be attributed to Chesapeake, and approximately 25% will be attributed to Total. The following table outlines the approximate aggregate minimum volume commitments for each year during the minimum volume commitment period:

LOGO

 

  (1) Includes a one-time carry forward of approximately 20 Bcf, which was carried forward from the minimum volume commitment for the six months ended December 31, 2009.
  (2) Indicated volumes relate to the six months ending June 30, 2019.

 

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In the event either Chesapeake or Total does not meet its minimum volume commitment, as adjusted in certain instances, to us for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such party for the six months ending June 30, 2019 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.

 

   

Fee Redetermination . We and each of Chesapeake and Total, as applicable, have the right to redetermine the Barnett Shale fee during a six-month period beginning September 30, 2011 and a two-year period beginning on September 30, 2014. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5% of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. If we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

 

   

Well Connection Requirement . Subject to required notice by Chesapeake and Total and certain exceptions, we have generally agreed to connect new operated drilling pads and new operated wells within our Barnett Shale region acreage dedications as requested by Chesapeake and Total during the minimum volume commitment period.

 

   

Fuel, Lost and Unaccounted For Gas and Electricity . We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas and electricity on our systems with respect to its volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed-upon cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, or lost or unaccounted for, and electricity, in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk. Please read “—Quantitative and Qualitative Disclosures About Market Risk” below.

Mid-Continent Region . Under our gas gathering agreement with Chesapeake, we have agreed to provide the following services in our Mid-Continent region to Chesapeake for the fees and obligations of Chesapeake outlined below:

 

   

Gathering, Treating and Compression Services . We gather, treat and compress natural gas in exchange for system-based services fees per Mcf for natural gas gathered and per Mcf for natural gas

 

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compressed, which we refer to as the Mid-Continent fees. The Mid-Continent fees for these systems are subject to an annual 2.5% rate escalation at the beginning of each year.

 

   

Acreage Dedication . Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication. For more detail on the acreage dedication, please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements” and “—Omnibus Agreement.”

 

   

Fee Redetermination . The Mid-Continent fees will be redetermined at the beginning of each year through 2019. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to, differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the Mid-Continent redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15% of the then current fees at the time of redetermination.

 

   

Well Connection Requirement . Subject to required notice by Chesapeake and certain exceptions, we have generally agreed to use our commercially reasonable efforts to connect new operated drilling pads and new operated wells in our Mid-Continent region acreage dedication as requested by Chesapeake through June 30, 2019.

 

   

Fuel, Lost and Unaccounted For Gas and Electricity . We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas and electricity on our systems with respect to their volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, or lost or unaccounted for, and electricity, in excess of such cap is based on then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk. Please see “—Quantitative and Qualitative Disclosures About Market Risk” below.

In the event that either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total, as applicable, or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total, as applicable.

Other Arrangements

Business Opportunities . Pursuant to our omnibus agreement, Chesapeake has agreed to provide us a right of first offer with respect to three specified categories of transactions: (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage dedications, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within five miles of the acreage dedications, and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with Chesapeake and our ability to obtain financing on acceptable terms. Notwithstanding the foregoing, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Although we will have certain rights with respect to the potential business opportunities, we are not under any contractual obligation to pursue any such transactions. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

 

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Services Arrangements . Under the omnibus agreement, Chesapeake has agreed to provide us with certain general and administrative services. We will reimburse Chesapeake for such services in any given month subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, treat or compress. The $0.03 per Mcf cap will be subject to an annual upward adjustment on October 1 of each year equal to 50% of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented after the closing of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Additionally, pursuant to an employee secondment agreement that we will enter into with Chesapeake upon the closing of this offering, specified employees of Chesapeake will be seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner will, subject to specified exceptions and limitations, reimburse Chesapeake on a monthly basis for all costs and expenses it incurs relating to such seconded employees. Additionally, under our employee transfer agreement, we will be required to maintain certain compensation standards for seconded employees to whom we make offers for hire. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Employee Secondment Agreement” and “—Employee Transfer Agreement.”

How We Evaluate Our Operations

Our results are driven primarily by our customers’ minimum volume commitments and the actual volumes of natural gas we gather, treat and compress. In the case of our Barnett Shale volumes, our results will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total. We contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the nine months ended September 30, 2009, Chesapeake and its working interest partners accounted for approximately 98% of the natural gas volumes on our gathering systems and our revenues on a pro forma basis.

Our management relies on certain financial and operational metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include (i) throughput volumes, (ii) operating expenses, (iii) Adjusted EBITDA and (iv) distributable cash flow.

Throughput Volumes

Although Chesapeake’s and Total’s respective 10-year minimum volume commitments generally provide us with protection in the event that throughput volumes from Chesapeake or Total, as applicable, in the Barnett Shale region do not meet certain levels (as described in more detail above under “—Our Gas Gathering Agreements”), our management analyzes our performance based on the aggregate amount of throughput volumes on our gathering systems in both our Barnett Shale and Mid-Continent regions from Chesapeake, Total and other third-party producers. We must connect additional wells within our Barnett Shale and Mid-Continent regions in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Operating Expenses

Our management seeks to maximize the profitability of our operations in part by minimizing operating expenses. These expenses are comprised primarily of field operating costs (which include labor, treating and chemicals and measurement services, among other items), compression expense, ad valorem and Texas

 

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franchise taxes and other operating costs, some of which are independent of the volumes through our systems but fluctuate depending on the scale of our operations during a specific period.

Chesapeake has extensive operational, commercial, technical and administrative personnel that we plan to utilize to enhance our operating efficiency and overall asset utilization. In some instances, these services are available to us at a low cost compared to the expense of developing these functions internally, and we intend to use Chesapeake personnel for many general and administrative services that represent a significant expense for competing midstream businesses.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income (loss) before income tax expense, interest expense, depreciation and amortization expense, certain non-cash charges, gains and losses from derivative activities and selected items that are generally unusual or non-recurring.

We define distributable cash flow as Adjusted EBITDA, plus interest income, less net cash paid for interest expense, maintenance capital expenditures and income taxes. Distributable cash flow does not reflect changes in working capital balances. Distributable cash flow and Adjusted EBITDA are not presentations made in accordance with GAAP.

Adjusted EBITDA and distributable cash flow are non-GAAP supplemental financial measures that management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

 

   

our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or, in the case of Adjusted EBITDA, financing methods;

 

   

our ability to incur and service debt and fund capital expenditures;

 

   

the ability of our assets to generate sufficient cash flow to make distributions to our unitholders; and

 

   

the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

We believe that the presentation of Adjusted EBITDA and distributable cash flow will provide useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to each of Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing its utility.

Items Impacting the Comparability of Our Financial Results

Our future results of operations may not be comparable to the historical results of operations for the periods presented below for our Predecessor, for the reasons described below:

 

   

On a pro forma basis, our assets constitute approximately 57% of the total assets of our Predecessor as of September 30, 2009. Accordingly, the results of operations of our Predecessor reflect a larger

 

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business than the business to be contributed to us. Please read “—Chesapeake Midstream Partners, L.P. and Our Predecessor” above for a more detailed discussion of the differences between our Predecessor and us.

 

   

The historical consolidated financial statements of our Predecessor cover periods in which our assets experienced significant growth. Due to the significant build-out of our gathering systems, capital expenditures by our Predecessor over the covered periods in our areas of operations were higher than those that we anticipate we will experience in future periods. Capital expenditures with respect to our assets for the year ended December 31, 2008 and the nine months ended September 30, 2009 were approximately $875.7 million and $253.7 million, respectively, and we anticipate incurring total capital expenditures of approximately $332.2 million for the year ending December 31, 2010.

 

   

As a result of Chesapeake’s upstream joint venture with Total, we anticipate that Chesapeake will increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth-quarter 2009 levels.

 

   

Our Predecessor incurred impairments of property, plant and equipment and other assets of $30.0 million and $86.2 million for the year ended December 31, 2008 and the nine months ended September 30, 2009, respectively, which we do not consider to be recurring events.

 

   

We anticipate incurring approximately $2.0 million of general and administrative expenses attributable to operating as a publicly traded partnership, such as expenses associated with annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These incremental general and administrative expenses are not reflected in the historical consolidated financial statements of our Predecessor.

 

   

Upon the closing of the offering, we will be required to reimburse Chesapeake on a monthly basis for the time and materials actually spent in performing certain general and administrative services on our behalf pursuant to the omnibus agreement. Our Predecessor reimbursed Chesapeake for these services in a similar manner. Our reimbursement to Chesapeake of general and administrative expenses in any given month will be subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process during that month. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.” The cap contained in the omnibus agreement does not apply to our direct general and administrative expenses or incremental general and administrative expenses that we expect to incur or to be allocated to us as a result of our becoming a publicly traded partnership.

 

   

We have entered into gas gathering agreements with each of Chesapeake and Total that include fees for gathering, treating and compressing natural gas that are higher than the average fees reflected in our Predecessor’s historical financial results prior to September 30, 2009. Please read “—Our Gas Gathering Agreements” above.

 

   

Our Predecessor’s historical consolidated financial statements include U.S. federal and state income tax expense incurred by it. Due to our status as a partnership, we will not be subject to U.S. federal income tax and certain state income taxes in the future.

 

   

Following the closing of this offering, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $              per unit per quarter ($              per unit on an annualized basis). Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Historically, our Predecessor largely relied on internally generated cash flows and capital contributions from Chesapeake to satisfy its capital expenditure requirements.

 

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General Trends and Outlook

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

Natural Gas Fundamentals and Operating Environment

Natural gas is a critical component of energy consumption in the U.S., accounting for approximately 24% of all energy used in 2008, representing approximately 23.3 Tcf of natural gas, according to the U.S. Energy Information Administration, or EIA. Over the next 27 years, the EIA estimates that total domestic energy consumption will increase by over 15%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles, and indirectly through additions of electric vehicles.

U.S. natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states and is supplemented by production from historically declining pipeline imports from Canada, imports of liquefied natural gas, or LNG, from foreign sources as well as some production in Alaska. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset an established trend of depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska. Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources, defined by the EIA as natural gas produced from shale formations and coalbeds, increasing from 9% of total U.S. natural gas supply in 2000 to 15% in 2008. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

The U.S. Geological Service, Mineral Management Service and EIA estimate that in 2010 the U.S. possesses over 2,000 Tcf of technically recoverable natural gas resources, an increase of approximately 30% from 2008 estimates of technically recoverable natural gas resources, which is primarily due to technological advancements. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecast to fill the void and continue to gain market share from higher-cost sources of natural gas. Natural gas production from the major shale formations is forecast to provide the majority of the growth in unconventional natural gas supply, increasing to approximately 24% of total U.S. natural gas supply in 2035 as compared with 6% in 2008. This represents a projected four-fold increase in natural gas shales’ market share of U.S. natural gas supply.

We operate in the Barnett Shale, the largest shale play by production volume in the U.S., and in several cost-advantaged unconventional natural gas plays in our Mid-Continent region. We believe that our focus on being the leading shale and unconventional natural gas gatherer, together with our relationship with Chesapeake, positions us to capitalize on these projected industry trends.

Although drilling in most unconventional resource plays is economical at current natural gas prices, the EIA forecasts a general increase in natural gas prices as more domestic resources are required to meet growing domestic energy demand. The EIA forecasts a 2015 Henry Hub natural gas price of $6.99 per MMBtu, increasing to $14.92 per MMBtu in 2035, an increase of approximately 279% over 2009 average Henry Hub pricing.

Our gas gathering agreements with Chesapeake and Total mitigate to some extent the potential impact of natural gas price movements. For example, the potential exists for a reduction in natural gas production in sustained periods of low natural gas prices and for increased operating costs in sustained periods of high natural

 

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gas prices. We believe our gas gathering agreements address these concerns in our Barnett Shale region through Chesapeake’s and Total’s minimum volume commitments and the Barnett Shale fee redetermination provision and in the Mid-Continent region through our annual fee redetermination provision. Notwithstanding such provisions, we remain subject to certain industry risks described in more detail in “Risk Factors.”

Interest Rate Environment

The credit markets recently have experienced near-record lows in interest rates. As the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent we may need to in the future to fund our growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise funds in the debt capital markets, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions 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 common units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, reduce debt or for other purposes. In the near-term, however, we believe that we will have a competitive advantage with respect to many other publicly traded partnerships in the midstream energy industry given our liquidity position at the closing of this offering. Please read “Business—Our Competitive Strengths—Conservative Capital Structure.”

Acquisition Opportunities

We may acquire additional midstream energy assets from Chesapeake. Pursuant to our omnibus agreement, subject to certain exceptions, we have a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operations, although Chesapeake will not be obligated to accept any offer we make. In addition, we may pursue selected asset acquisitions from third parties to the extent such acquisitions complement our or Chesapeake’s existing asset base or allow us to capture operational efficiencies from Chesapeake’s production. As a result of the recent credit crisis and resulting downturn in commodity price levels and the subsequent re-emergence of access to credit and the capital markets, we expect that the midstream energy industry will experience a higher level of acquisition and divestiture activity in the near term than in recent years. We believe that we will be well-positioned to acquire midstream assets from third parties should opportunities arise. If we do not make acquisitions from Chesapeake or third parties on economically acceptable terms, our future growth will be limited, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per-unit basis.

 

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Results of Operations—Combined Overview

The following table and discussion presents a summary of our Predecessor’s consolidated results of operations for the years ended December 31, 2006, 2007 and 2008 and the nine months ended September 30, 2008 and 2009:

 

     Predecessor Consolidated  
     Year Ended December 31,     Nine Months Ended
September 30,
 
     2006    2007    2008     2008     2009  
     (In thousands, except operating data)  

Revenues

   $ 100,590    $ 191,931    $ 332,783      $ 234,678      $ 358,921   

Operating expenses

     34,914      77,589      141,803        97,419        146,604   

General and administrative expense

     2,766      6,880      13,362        9,400        22,782   

Depreciation and amortization expense

     9,761      24,505      47,558        31,529        65,477   
                                      

Total operating expenses

     47,441      108,974      202,723        138,348        234,863   
                                      

Operating income

     53,149      82,957      130,060        96,330        124,058   

Interest expense

     —        —        1,871        —          347   

(Gain) loss on sale of assets

     —        —        (5,541     (6,242     44,566   

Other expense (income)

     —        —        (278     (306     (29

Impairment of property, plant and equipment and other assets

     —        —        30,000        —          90,207   
                                      

Income (loss) before income taxes

     53,149      82,957      104,008        102,878        (11,033

Income tax expense (benefit)

     19,931      31,109      (61,287     (62,986     6,341   
                                      

Net income (loss)

   $ 33,218    $ 51,848    $ 165,295      $ 165,864      $ (17,374
                                      

Operating Data:

            

Throughput, MMcf/d

     588      1,018      1,585        1,529        2,089   

Average rate per Mcf

   $ 0.47    $ 0.52    $ 0.58      $ 0.56      $ 0.63   

Predecessor—Nine Months Ended September 30, 2009 vs. Nine Months Ended September 30, 2008

Revenues . Total revenues increased $124.2 million, or 53%, to $358.9 million for the nine months ended September 30, 2009 from $234.7 million for the nine months ended September 30, 2008. Total volumetric throughput increased approximately 153 Bcf, or 37%, to approximately 570 Bcf for the nine months ended September 30, 2009 from approximately 417 Bcf for the nine months ended September 30, 2008. Average rates increased $0.07 per Mcf, or 13%, to $0.63 per Mcf for the nine months ended September 30, 2009 from $0.56 per Mcf for the nine months ended September 30, 2008. The increase was primarily due to additional throughput volumes resulting from the expansion of gathering systems primarily in the Barnett Shale as well as an increase in rates in the Barnett Shale and Mid-Continent regions charged effective July 1, 2009.

The table below reflects our Predecessor’s revenues and throughput by region for the nine months ended September 30, 2008 and 2009:

 

     Predecessor
     Nine Months Ended
September 30, 2008
   Nine Months Ended
September 30, 2009
     Revenues    Throughput
(MMcf)
   Revenues    Throughput
(MMcf)
     (In thousands, except operating data)

Barnett Shale

   $ 140,486    185,311    $ 201,217    248,073

Mid-Continent

     60,878    168,210      76,388    172,564

Fayetteville Shale

     26,046    41,442      52,314    78,782

Haynesville Shale

     7,268    22,531      24,106    60,752

Appalachian Basin

     —      —        4,896    10,189
                       
   $ 234,678    417,494    $ 358,921    570,360
                       

 

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Operating Expenses . Operating expenses increased $49.2 million, or 50%, to $146.6 million for the nine months ended September 30, 2009 from $97.4 million for the nine months ended September 30, 2008. Operating expenses increased $0.03 per Mcf, or 13%, to $0.26 per Mcf for the nine months ended September 30, 2009 from $0.23 per Mcf for the nine months ended September 30, 2008. This increase was primarily the result of the expansion of our Predecessor’s scale of operations in the Barnett Shale region.

The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the nine months ended September 30, 2008 and 2009:

 

     Predecessor
     Nine Months Ended
September 30, 2008
   Nine Months Ended
September 30, 2009
     Operating
Expenses
   Expenses
($ per Mcf)
   Operating
Expenses
   Expenses
($ per Mcf)
     (In thousands, except per unit data)

Barnett Shale

   $ 56,424    $ 0.30    $ 73,505    $ 0.30

Mid-Continent

     25,168      0.15      36,987      0.21

Fayetteville Shale

     13,739      0.33      27,509      0.35

Haynesville Shale

     2,088      0.09      5,784      0.10

Appalachian Basin

     —        —        2,819      0.28
                           
   $ 97,419    $ 0.23    $ 146,604    $ 0.26
                           

General and Administrative Expense . General and administrative expense increased $13.4 million, or 143%, to $22.8 million for the nine months ended September 30, 2009 from $9.4 million for the nine months ended September 30, 2008. During the nine months ended September 30, 2009, our Predecessor incurred approximately $3.3 million of charges associated with the completion of the joint venture with GIP. The remaining increase was primarily the result of the expansion of our Predecessor’s operations and the resulting increase in personnel and related expenses to support that growth.

Depreciation and Amortization Expense . Depreciation and amortization expense increased $34.0 million, or 108%, to $65.5 million for the nine months ended September 30, 2009 from $31.5 million for the nine months ended September 30, 2008, primarily as a result of the addition of new gathering systems in the nine months ended September 30, 2009 and the realization of nine months’ depreciation on property, plant and equipment and other assets added during the year ended December 31, 2008.

Interest Expense . Interest expense for the nine months ended September 30, 2009 was $347,000, which is net of $6.5 million of capitalized interest, compared to zero for the nine months ended September 30, 2008. Interest expense recorded for the nine months ended September 30, 2009 is related to borrowings under our Predecessor’s revolving credit facility that was established in October of 2008.

(Gain) Loss on Sale of Assets . Our Predecessor recorded a $44.6 million loss on the sale of certain non-core and non-strategic gathering systems during the nine months ended September 30, 2009 compared to a $6.2 million gain on the sale of certain gathering systems sold in conjunction with an upstream transaction effected by Chesapeake during the nine months ended September 30, 2008.

Impairment of Property, Plant and Equipment and Other Assets . Impairment of property, plant and equipment and other assets for the nine months ended September 30, 2009 was $90.2 million compared to zero for the nine months ended September 30, 2008. Our Predecessor recorded an $86.2 million impairment associated with certain gathering systems located in the Mid-Continent region that are not expected to have future cash flows in excess of the book value of these systems. These systems were subsequently contributed to Chesapeake MLP Operating, L.L.C. Additionally, $4 million of debt issuance costs were expensed as a result of the amendment of our Predecessor’s $460 million credit facility.

 

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Income Tax Expense (Benefit) . Our Predecessor recorded income tax expense of $6.3 million for the nine months ended September 30, 2009 compared to income tax benefit of $63.0 million for the nine months ended September 30, 2008. Prior to February 2008, our Predecessor filed consolidated federal income and state returns with Chesapeake as required by law. In February 2008, upon and subsequent to contribution of assets to our Predecessor by Chesapeake, our Predecessor and certain of its subsidiaries became pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements. As such, our Predecessor has provided for the change in legal structure which occurred in 2008 by recording $63.0 million of income tax benefit for the nine months ended September 30, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to our Predecessor’s remaining taxable entity that was not contributed to us and is based on the 37.5% effective corporate tax rate of our Predecessor.

Predecessor—Year Ended December 31, 2008 vs. Year Ended December 31, 2007

Revenues . Total revenues increased $140.9 million, or 73%, to $332.8 million in 2008 from $191.9 million in 2007. Total volumetric throughput increased approximately 206 Bcf, or 55%, to 578 Bcf for 2008 from 372 Bcf for 2007. Average rates increased $0.06 per Mcf, or 12%, to $0.58 per Mcf for 2008 from $0.52 per Mcf for 2007. The increase was primarily due to additional throughput volumes resulting from the expansion of gathering systems primarily in the Barnett Shale region.

The table below reflects our Predecessor’s revenues and throughput by region for the years ended December 31, 2007 and 2008:

 

     Predecessor
     Year Ended
December 31, 2007
   Year Ended
December 31, 2008
     Revenues    Throughput
(MMcf)
   Revenues    Throughput
(MMcf)
     (In thousands, except operating data)

Barnett Shale

   $ 102,085    117,805    $ 198,424    257,930

Mid-Continent

     73,491    213,984      84,080    225,675

Fayetteville Shale

     9,031    10,155      38,586    58,868

Haynesville Shale

     7,324    29,735      11,641    35,852

Appalachian Basin

     —      —        52    133
                       
   $ 191,931    371,679    $ 332,783    578,458
                       

Operating Expenses . Operating expenses increased $64.2 million, or 83%, to $141.8 million in 2008 from $77.6 million in 2007. Operating expenses increased $0.04 per Mcf, or 19%, to $0.25 per Mcf for 2008 from $0.21 per Mcf for 2007. This increase was primarily the result of the expansion of our Predecessor’s operations primarily in the Barnett Shale region. The increase was driven by higher costs for 2008 compared to 2007 for labor, supplies and equipment incurred in the expansion of certain of our Predecessor’s gathering systems as well as increased costs for these services.

 

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The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the years ended December 31, 2007 and 2008:

 

     Predecessor
     Year Ended
December 31, 2007
   Year Ended
December 31, 2008
     Operating
Expenses
   Expenses
($ per Mcf)
   Operating
Expenses
   Expenses
($ per Mcf)
     (In thousands, except per unit data)

Barnett Shale

   $ 42,952    $ 0.36    $ 80,919    $ 0.31

Mid-Continent

     27,473      0.13      37,211      0.16

Fayetteville Shale

     5,002      0.49      20,035      0.34

Haynesville Shale

     2,162      0.07      3,606      0.10

Appalachian Basin

     —        —        32      0.24
                           
   $ 77,589    $ 0.21    $ 141,803    $ 0.25
                           

General and Administrative Expense . General and administrative expense increased $6.5 million or 94%, to $13.4 million in 2008 from $6.9 million in 2007. This increase was primarily the result of the expansion of our Predecessor’s operations and the resulting increase in personnel and related expenses to support that growth.

Depreciation and Amortization Expense . Depreciation and amortization expense increased $23.1 million, or 94%, to $47.6 million in 2008 from $24.5 million in 2007, primarily as a result of the addition of new gathering systems and the realization of a full year’s depreciation on property, plant and equipment and other assets added throughout the course of the year in 2007.

Interest Expense . Interest expense for 2008 was $1.9 million compared to zero for 2007. Interest expense recorded for 2008 is related to borrowings under our Predecessor’s revolving credit facility that was established in October 2008.

(Gain) Loss on Sale of Assets . Our Predecessor recorded a gain of $5.5 million in 2008 on the sale of certain gathering systems sold in conjunction with an upstream transaction executed by Chesapeake. No gain or loss was recorded in 2007.

Impairment of Property, Plant and Equipment and Other Assets . Our Predecessor recorded a $30.0 million impairment of property, plant and equipment and other assets for 2008 associated with certain of its treating assets as a result of a continued expected decline in throughput with respect to such assets. No impairment was recorded in 2007.

Income Tax Expense (Benefit) . Our Predecessor recorded income tax benefit of $61.3 million in 2008 compared to income tax expense of $31.1 million in 2007. Historically, our Predecessor filed a consolidated federal income tax return and state returns as required with Chesapeake. Our Predecessor’s 2007 income tax expense was based on a 37.5% effective corporate income tax rate of our Predecessor. In February 2008, upon and subsequent to contribution of assets to our Predecessor by Chesapeake, our Predecessor and certain of its subsidiaries became a partnership and limited liability companies, respectively, and were subsequently treated as pass through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the financial statements. As such, our Predecessor has provided for the change in legal structure which occurred in 2008 by recording a $63.0 million income tax benefit for the nine months ended September 30, 2008. Accordingly, our Predecessor’s effective income tax rate for the year ended December 31, 2008 was 58.9%.

 

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Predecessor—Year Ended December 31, 2007 vs. Year Ended December 31, 2006

Revenues . Total revenues increased $91.3 million, or 91%, to $191.9 million in 2007 from $100.6 million in 2006. Total volumetric throughput increased approximately 157 Bcf, or 73%, to 372 Bcf for 2007 from 215 Bcf for 2006. Average rates increased $0.05 per Mcf, or 11%, to $0.52 per Mcf for 2007 from $0.47 per Mcf for 2006. The increase was primarily due to additional throughput volumes resulting from the expansion of gathering systems primarily in the Barnett Shale region.

The table below reflects our Predecessor’s revenues and throughput by region for the years ended December 31, 2006 and 2007:

 

     Predecessor
     Year Ended
December 31, 2006
   Year Ended
December 31, 2007
     Revenues    Throughput
(MMcf)
   Revenues    Throughput
(MMcf)
     (In thousands, except operating data)

Barnett Shale

   $ 40,714    48,623    $ 102,085    117,805

Mid-Continent

     52,490    137,251      73,491    213,984

Fayetteville Shale

     625    594      9,031    10,155

Haynesville Shale

     6,761    28,198      7,324    29,735
                       
   $ 100,590    214,666    $ 191,931    371,679
                       

Operating Expenses . Operating expenses increased $42.7 million, or 122%, to $77.6 million in 2007 from $34.9 million in 2006. Operating expenses increased $0.05 per Mcf, or 31%, to $0.21 per Mcf for 2007 from $0.16 per Mcf for 2006. This increase was primarily the result of the expansion of our Predecessor’s scale of operations and increased throughput during 2007. The increase was driven by higher costs for 2007 compared to 2006 for labor, supplies and equipment incurred in the expansion of certain of our Predecessor’s gathering systems as well as increased costs for these services.

The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the years ended December 31, 2006 and 2007:

 

     Predecessor
     Year Ended
December 31, 2006
   Year Ended
December 31, 2007
     Operating
Expenses
   Expenses
($ per Mcf)
   Operating
Expenses
   Expenses
($ per Mcf)
     (In thousands, except per unit data)

Barnett Shale

   $ 15,670    $ 0.32    $ 42,952    $ 0.36

Mid-Continent

     17,268      0.13      27,473      0.13

Fayetteville Shale

     712      1.20      5,002      0.49

Haynesville Shale

     1,264      0.04      2,162      0.07
                           
   $ 34,914    $ 0.16    $ 77,589    $ 0.21
                           

General and Administrative Expense . General and administrative expense increased $4.1 million, or 146%, to $6.9 million in 2007 from $2.8 million in 2006. This increase was primarily the result of the expansion of our Predecessor’s operations and the resulting increase in personnel levels to support that growth.

Depreciation and Amortization Expense . Depreciation and amortization expense increased $14.7 million, or 150%, to $24.5 million in 2007 from $9.8 million in 2006, primarily as a result of the addition of new gathering systems and the realization of a full year’s depreciation on property plant and equipment added throughout the course of the year in 2006.

 

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Income Tax Expense (Benefit). Income tax expense increased $11.2 million, or 56%, to $31.1 million in 2007 from $19.9 million in 2006. This increase was due to the increase in income before income taxes. Our Predecessor’s effective income tax rate for both periods was 37.5%.

Liquidity and Capital Resources

Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control.

Our Predecessor’s Liquidity and Capital Resources

Historically, our Predecessor’s sources of liquidity included cash generated from operations, funding from Chesapeake and borrowings under our Predecessor’s revolving credit facility.

Working Capital (Deficit). Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of September 30, 2009, our Predecessor had working capital of $155.4 million compared to a working capital deficiency of ($60.7) million at December 31, 2008. Both our Predecessor’s and our working capital changes are driven by changes in accounts receivable and accounts payable. These changes are primarily impacted by the level of spending for expansion and maintenance activity. Our Predecessor’s working capital increase was the result of an increase in our cash on hand following the September 30, 2009 formation of the joint venture between Chesapeake and GIP as well as higher accounts receivable generated from an increase in our throughput resulting from expansion projects completed and an increase in our inventory levels. Our Predecessor had a working capital deficiency of ($4.6) million at September 30, 2009 compared to a deficiency of ($99.9) million at December 31, 2008. The decrease in deficiency was primarily driven by a decrease in our accounts payable from December 31, 2008 to September 30, 2009 resulting from the completion of major projects during the respective period.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities for the years ended December 31, 2006, 2007 and 2008, and for the nine months ended September 30, 2008 and 2009 were as follows:

 

     Predecessor  
     Year Ended
December 31,
    Nine Months Ended
September 30,
 
     2006     2007     2008     2008     2009  
     (In thousands)  

Cash Flow Data:

          

Net cash provided by (used in):

          

Operating activities

   $ 55,587     $ 93,948     $ 236,774     $ 134,473     $ 100,748  

Investing activities

   $ (218,843   $ (563,564   $ (1,384,834   $ (867,786   $ (690,994

Financing activities

   $ 163,272     $ 469,622     $ 1,230,059     $ 733,316     $ 664,268  

Operating Activities. Net cash provided by operating activities decreased by $33.7 million, or 25%, for the nine months ended September 30, 2009 as compared to 2008. This decrease was primarily attributable to an increase in cash flow from operations offset by changes in working capital for the nine months ended September 30, 2009. Net cash provided by operating activities increased by $142.8 million in 2008 as compared to 2007. This increase was the result of the cash generated by expansion projects placed into service in 2008. Net cash provided by operating activities increased by $38.4 million in 2007 as compared to 2006. This increase was also the result of the cash generated by expansion projects placed into service in 2007.

Investing Activities. Net cash used in investing activities decreased by $176.8 million, or 20%, for the nine months ended September 30, 2009 as compared to 2008. This decrease was primarily attributed to the continued

 

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maturing of the Barnett Shale region and the completion of certain major projects. Net cash used in investing activities increased by $821.3 million, or 146%, in 2008 as compared to 2007, and net cash used in investing activities increased by $344.7 million, or 158%, in 2007 as compared to 2006. These increases were the result of increases in expansion capital expenditures as a result of the development of Chesapeake’s drilling program in our Barnett Shale and the Mid-Continent regions.

Financing Activities. Our Predecessor’s financing requirements have been managed historically with cash generated by operations and equity contributions from Chesapeake. On October 15, 2008, our Predecessor entered into a revolving credit facility agreement with total commitments of $460 million. Prior to entering into the revolving credit facility in October 2008, Chesapeake provided cash management services to our Predecessor through a centralized treasury system. As a result, all of our Predecessor’s charges and cost allocations covered by the centralized treasury system were deemed to have been paid to Chesapeake in cash, during the period in which the cost was recorded in the financial statements. In addition, cash advanced by Chesapeake in excess of earnings by our Predecessor has been reflected as contributions from Chesapeake in the statement of division equity.

Net cash provided by financing activities decreased by $69.0 million, or 9%, for the nine months ended September 30, 2009 as compared to 2008. This decrease is primarily attributable to decreased cash contributions from Chesapeake related to the continued maturing of the Barnett Shale region and the completion of certain major projects. Net cash provided by financing activities increased by $760.4 million, or 162%, for the year ended December 31, 2008 as compared to 2007. This increase is due to additional cash contributions by Chesapeake of $310.9 million as well as $449.5 million of revolving credit facility net proceeds that were required as a result of the development of Chesapeake’s drilling program. Net cash provided by financing activities increased $306.4 million, or 188%, for the year ended December 31, 2007 as compared to 2006. This increase is a result of additional cash contributions by Chesapeake.

Capital Expenditures . For the year ended December 31, 2008 and the nine months ended September 30, 2009, our Predecessor’s total capital expenditures were $1,402 million and $756.9 million, respectively, and primarily associated with the continued build-out of gathering systems in its primary areas of operations.

Our Liquidity and Capital Resources

Following the completion of this offering, we expect our sources of liquidity to include:

 

   

cash on hand of $             million after the application of a portion of the net proceeds from this offering to repay borrowings outstanding under our revolving credit facility as described in “Use of Proceeds”;

 

   

cash generated from operations;

 

   

borrowings under our $500 million syndicated revolving credit facility; and

 

   

future issuances of equity and debt securities.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to fund our quarterly cash distributions to unitholders.

Revolving Credit Facility . In connection with the completion of this offering, we expect to amend and restate our revolving credit facility that will mature in September 2012 to permit the material terms of our partnership agreement and other material agreements entered into upon the closing of this offering. As of the completion of this offering, after giving effect to the application of the net proceeds from this offering in the manner described in “Use of Proceeds,” we expect to have no outstanding borrowings under this facility.

Borrowings under the revolving credit facility will be secured by all of our assets and will bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal

 

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funds effective rate plus 0.50%, and the one-month LIBOR plus 1.0%, all of which would be subject to a margin that varies from 2.0% to 2.75% per annum according to the most recent consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness on any day to consolidated EBITDA for the most recent four consecutive fiscal quarters for which financial statements are available) or (ii) the LIBOR plus a margin that varies from 3.0% to 3.75% per annum according to the most recent consolidated leverage ratio. The unused portion of the revolving credit facility will be subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest will be payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals.

The revolving credit facility will require maintenance of a consolidated leverage ratio of not more than 3.50 to 1, and an interest coverage ratio (which is defined as the ratio of consolidated EBITDA for the most recent four consecutive four fiscal quarters to consolidated interest expense for such period) of not less than 3.00 to 1. As defined by the revolving credit facility at September 30, 2009, our consolidated leverage ratio was 0.09 to 1 and our interest coverage ratio was 17.49 to 1.

Additionally, our revolving credit facility contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If we should fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility will also have cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.

Capital Requirements . Our business can be capital-intensive, requiring significant investment to maintain and improve existing assets. We categorize capital expenditures as either:

 

   

maintenance capital expenditures, which include those expenditures required to maintain the existing operating capacity and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

 

   

expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, to expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels, reduce costs or increase revenues.

We have budgeted approximately $332.2 million in capital expenditures for the year ending December 31, 2010, of which $252.2 million represents expansion capital expenditures and $80 million represents maintenance capital expenditures. Our capital expenditures for the year ending December 31, 2010 are primarily concentrated in our Barnett Shale region and in the Colony Granite Wash and Texas Panhandle Granite Wash plays in our Mid-Continent region. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute all of our available cash to our unitholders, we expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities.

Distributions . We intend to pay a minimum quarterly distribution of $             per unit per quarter, which equates to $             million per quarter, or $             million per year, based on the number of common,

 

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subordinated and general partner units to be outstanding immediately after completion of this offering. We do not have a legal obligation to pay this distribution. Please read “Our Cash Distribution Policy and Restrictions on Distributions.”

Contractual Obligations . The table below summarizes our contractual obligations and other commitments as of September 30, 2009:

 

Contractual Obligation (In thousands)

   Total    Less than
1 Year
   1-3
Years
   3-5
Years
   More than
5 Years

Long-term debt

   $ 12,173    $ —      $ —      $ 12,173    $ —  

Operating leases (1)

     139,960      45,780      90,584      2,196      1,400

Asset retirement obligations

     2,699      —        —        —        2,699

 

(1) We lease certain real property, equipment and operating facilities under various operating leases. We also incur costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. The amounts above represent future non-cancellable commitments.

In addition to the above obligations, we are required to reimburse Chesapeake on a monthly basis for the time and materials actually spent in performing certain general and administrative services on our behalf pursuant to the omnibus agreement. Our reimbursement to Chesapeake of these general and administrative expenses in any given month is subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process. The $0.03 per Mcf cap will be subject to an annual upward adjustment on October 1 of each year equal to 50% of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented after the closing of the offering. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.” The cap contained in the omnibus agreement does not apply to our direct general and administrative expenses or incremental general and administrative expenses that we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership. We currently expect those expenses to be approximately $2.0 million per year. We also expect that our general partner will, subject to specified exceptions and limitations, reimburse Chesapeake on a monthly basis for all costs and expenses Chesapeake incurs relating to employees seconded to us, including the cost of their salaries and employee benefits, including 401(k), restricted stock grants and health insurance benefits.

Off-Balance Sheet Arrangements

We do not anticipate that we will have any off-balance sheet arrangements as of the closing of this offering.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us and our Predecessor to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. We and our Predecessor make significant estimates including: (i) estimated useful lives of assets, which impacts depreciation; (ii) accruals related to revenues, expenses and capital costs; and (iii) liability and contingency accruals. Although we and our Predecessor believe these estimates are reasonable, actual results could differ from our estimates.

Property, Plant and Equipment and Other Assets

Property, plant and equipment and other assets are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As

 

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assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in other income in the statements of operations.

Depreciation is calculated using the straight-line method, based on the estimated useful lives of our assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions and supply and demand in the area. When assets are put into service, we and our Predecessor make estimates with respect to useful lives and salvage values that we believe and our Predecessor believes, respectively, are reasonable. However, subsequent events could cause us to change our estimates, thus impacting the future calculation of depreciation. The estimated service lives of our functional asset groups are as follows:

 

Asset Group

   Estimated Useful Lives
(In years)

Gathering systems

   20

Other fixed assets

   2 to 39

Certain of our gathering systems are subject to an agreement with Chesapeake, which provides us rights and obligations equivalent to a capital lease. Under the terms of the agreement, we have rights to the associated capital assets for as long as the assets are in operation. Specifically, we will pay all costs associated with the related gathering systems, including all capital costs, operating costs, and direct and indirect overhead costs. In exchange for paying such costs and for the services we provide pursuant to this agreement, we receive revenues derived from operation of the gathering systems. At September 30, 2009, approximately $121.4 million ($115.7 million net of accumulated depreciation) of our gathering system assets were held under such agreement. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, we have no capital lease obligation liability associated with the assets held under this agreement as of September 30, 2009.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value in accordance with accounting guidance for the impairment or disposal of long-lived assets. Under this guidance, assets are tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows.

Asset Retirement Obligation

We and our Predecessor follow accounting guidance for asset retirement obligations. This guidance applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. This standard requires that the fair value of a liability for a retirement obligation be recognized in the period in which the liability is incurred.

We and our Predecessor have leased properties for the purpose of installing central compressor stations to aid in the transportation of natural gas. Certain of the lease agreements require us and our Predecessor to restore the properties to their original condition at the expiration of the lease agreement. In these cases, we and our Predecessor have estimated the costs to remove the facilities and otherwise restore the property to its original condition and have recorded a liability which is included in other long-term liabilities. The asset retirement cost is capitalized as part of the carrying amount of our gathering systems at its discounted fair value. The liability is then accreted each period until the liability is settled or the gathering system is sold, at which time the liability is reversed.

 

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Revenue Recognition

Our Predecessor’s revenues are derived almost exclusively from related parties and are charged under long-term contracts at market sensitive rates. We currently derive substantially all of our revenues through our gas gathering agreements with Chesapeake and Total. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments covering production in our Barnett Shale region for each year through December 31, 2018 and for the six month period ending June 30, 2019. In the event either Chesapeake or Total does not meet its minimum volume commitment to us for any annual period (or six month period with respect to the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which such party’s minimum volume commitment for such year (or six month period with respect to the six months ending June 30, 2019) exceeds the actual volumes gathered on our systems from such party’s production. The revenue associated with such shortfall fees will be recognized in the fourth quarter of each year.

Revenues consist of fees recognized for the gathering, treating and compressing of natural gas to major intrastate pipelines. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating and compressing volumes.

Environmental Remediation

Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

Quantitative and Qualitative Disclosures About Market Risk

We are dependent on Chesapeake and Total for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake and Total of gathering, treating and compression fees, as applicable. Chesapeake’s credit ratings are below investment grade, and its credit ratings may remain below investment grade for the foreseeable future. Additionally, neither of our Total counterparties under our gas gathering agreement, nor the Total guarantor of those counterparties, are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

Interest Rate Risk

Interest rates have recently experienced near record lows. If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances. We intend to use a portion of the proceeds from this offering to repay all outstanding borrowings under our revolving credit facility. Accordingly, unless and until we have outstanding a material amount of borrowings on our revolving credit facility or other outstanding indebtedness, we do not expect to have any material floating interest rate risk.

Commodity Price Risk

We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering agreements with Chesapeake and Total that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in

 

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natural gas prices could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding the minimum volume commitments of Chesapeake and Total in our Barnett Shale region and the fee redetermination provisions under our gas gathering agreements, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flow from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.

We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas and electricity on our systems with respect to its volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, or lost or unaccounted for, and electricity, in excess of such cap based on the then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as costs of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.

Recent Accounting Pronouncements

In June 2009, the Financial Accounting Standards Board (“FASB”) issued the FASB Accounting Standards Codification (the “Codification”) to establish a single source of authoritative nongovernmental U.S. generally accepted accounting principles (“U.S. GAAP”). The Codification is meant to (i) simplify user access by codifying all authoritative U.S. GAAP into one location, (ii) ensure that codified content accurately represents authoritative U.S. GAAP and (iii) create a better structure and research system for U.S. GAAP. The Codification was effective for interim or annual periods ending after September 15, 2009; therefore, we adopted this guidance as of July 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In May 2009, the FASB issued guidance that establishes general standards of accounting for and disclosure of subsequent events for events that occur after the balance sheet date but before financial statements are issued. This guidance sets forth (i) the period after the balance sheet date during which management shall evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements, (ii) the circumstances under which an entity shall recognize events or transactions occurring after the balance sheet date in its financial statements and (iii) the disclosures that an entity shall make about events or transactions that occurred after the balance sheet date. This guidance was effective for interim or annual periods ending after June 15, 2009; therefore, we adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In April 2009, the FASB issued guidance that increases the frequency of fair value disclosures from annual to quarterly in an effort to provide financial statement users with more timely and transparent information about the effects of current market conditions on financial instruments. This is intended to address concerns raised by some financial statement users about the lack of comparability resulting from the use of different measurement attributes for financial instruments. These disclosures are also intended to stimulate more robust discussions about financial instrument valuations between users and reporting entities. We adopted this guidance as of April 1, 2009. Adoption did not have any material impact on our financial position, results of operations or cash flows.

In March 2008, the Emerging Issues Task Force of the FASB reached a final consensus on the two-class method of earnings per share related to master limited partnerships, or MLPs. Their conclusion affects how a master limited partnership allocates income between its general partner, which typically holds incentive distribution rights, or IDRs, along with the general partner interest, and the limited partners. It is not uncommon

 

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for MLPs to experience timing differences between the recognition of income and partnership distributions. The amount of incentive distribution is typically calculated based on the amount of distributions paid to the MLP’s partners. The issue is whether current period earnings of an MLP should be allocated to the holders of IDRs as well as the holders of the general and limited partner interests when applying the two-class method.

Their conclusion was that when current period earnings are in excess of cash distributions, the undistributed earnings should be allocated to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders based upon the terms of the partnership agreement. Under this model, contractual limitations on distributions to incentive distribution rights holders would be considered when determining the amount of earnings to allocate to them. That is, undistributed earnings would not be considered available cash for purposes of allocating earnings to incentive distribution rights holders. Conversely, when cash distributions are in excess of earnings, net income (or loss) should be reduced (increased) by the distributions made to the holders of the general partner interest, the holders of the limited partner interest and incentive distribution rights holders. The resulting net loss would then be allocated to the holders of the general partner interest and the holders of the limited partner interest based on their respective sharing of the losses based upon the terms of the partnership agreement.

This is effective for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years. The accounting treatment is effective for all financial statements presented. We do not expect the impact of the adoption of this item on its presentation of earnings per unit to be significant.

 

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INDUSTRY

General

The midstream natural gas industry provides the link between the exploration for, and the production of, raw natural gas and the delivery of that natural gas and its by-products to industrial, commercial and residential end users. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing and treating plants to natural gas producing wells. The principal components of the business consist of gathering, compressing, dehydrating, processing, treating, fractionating, marketing and transporting natural gas and natural gas liquids.

The following diagram illustrates how natural gas moves from the wellhead to the end user:

LOGO

Service Types

The range of services provided by midstream natural gas service providers are generally divided into the following six categories:

Gathering . Gathering systems consist of networks of pipelines connected to individual wellheads and central receipt points that gather raw natural gas to central locations for processing, treating and compressing. A large gathering system may involve thousands of miles of gathering pipelines connected to thousands of wells. Gathering systems are often engineered to accommodate the gathering of natural gas at different pressures.

Compression . Natural gas compression is a mechanical process that involves increasing the pressure of natural gas in order to allow for more gas to flow through the same diameter pipeline and to enable delivery into higher pressure long-haul pipeline systems. Field compression is typically used to lower the gas pressure at the entry point of a gathering system, while providing sufficient pressure upon exit of the gathering system to deliver gas into higher pressure long-haul pipeline systems. Because wells produce at progressively lower field pressures as the underlying resources are depleted, field compression is required to maintain sufficient pressure across the gathering system.

Treating and Dehydration . Natural gas treating and dehydration involve the removal of impurities such as water, carbon dioxide and hydrogen sulfide that may be present when natural gas is produced at the wellhead in order to meet the specifications of long-haul intrastate and interstate pipelines. To the extent that gathered natural gas contains saturated water and contaminants, the natural gas may be dehydrated in order to remove any saturated water contained in the gas stream and may be treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

Processing . Natural gas processing involves the separation of the various hydrocarbons and fluids from raw natural gas to produce “dry” natural gas that meets the specifications of long-haul intrastate and interstate

 

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transportation pipelines. The principal component of natural gas is methane; however, natural gas may also contain varying amounts of heavier hydrocarbon components called natural gas liquids (NGLs). Natural gas is frequently described as “lean” or “rich” depending on the percentage content of NGLs that it contains, with “lean” referring to low NGL content gas and “rich” referring to high NGL content gas. “Lean gas” requires less processing, whereas “rich gas” contains NGLs that must be removed in order to meet the quality specifications of long-haul intrastate and interstate pipelines. The removal and separation of NGLs usually takes place in a relatively centralized processing plant using industrial processes that exploit the differences among the various products in weight, boiling point, vapor pressure and other physical characteristics.

Fractionation . NGL fractionation facilities separate mixed NGL streams into discrete NGL products such as ethane, propane, normal butane, isobutane and natural gasoline. Fractionation is effected by heating the mixed NGL stream to allow for the separation of the component parts based on the specific boiling points of each product. As the temperature of the stream is increased, the lighter NGL components boil off and become gases that reach the top of a distillation tower and then condense into pure component liquids. The remaining NGLs in the stream are then routed to successive distillation towers where the process is repeated until all of the discrete components have been separated. The discrete NGLs are then marketed to end users where they are utilized in various industrial processes such as enhanced oil recovery and the fabrication of petroleum and chemical products.

Transmission . The transmission of natural gas involves the movement of pipeline-quality natural gas from gathering systems to wholesalers and end users including industrial plants and local distribution companies (LDCs). LDCs purchase the natural gas from transmission companies and market the gas directly to commercial industrial and residential end users. Transmission pipelines generally span great distances and consist of large diameter pipelines that operate at higher pressures than gathering pipelines in order to transport the large quantities of natural gas required by end users. The concentration of natural gas production in a few regions of the U.S. generally requires transmission pipelines to cross state borders to meet national demand. These pipelines are referred to as interstate pipelines and are primarily regulated by federal agencies or commissions. Pipelines that transport natural gas produced and consumed wholly within one state are generally referred to as intrastate pipelines. Intrastate pipelines are primarily regulated by state agencies or commissions.

Typical Contractual Arrangements

The midstream services described above, with the exception of transmission, are typically provided on an integrated basis pursuant to a contractual arrangement between the producer of the raw natural gas stream and a gatherer/processor midstream service provider. For gas gatherers/processors, there are multiple forms of gathering contracts, which vary with respect to how much direct commodity price risk is borne by the gatherer/processor. Three typical contract types are described below:

Fee-Based . The gatherer/processor receives a fee per unit of natural gas gathered at the wellhead, compressed and treated. Depending on the fee structure, customers may pay a single fee for gathering, treating and compressing, or those services may be unbundled. Under fee-based arrangements, a midstream service provider bears no direct commodity price risk.

Percent-of-Proceeds . The gatherer/processor remits to the producers a percentage of the proceeds from the sales of residue gas and/or NGLs or a percentage of the residue gas and/or NGLs at the tailgate. These types of arrangements expose the gatherer/processor to direct commodity price risk because the revenues from these contracts directly correlate with the fluctuating price of natural gas and/or NGLs.

Keep-Whole . The gatherer/processor retains all or a portion of the NGLs produced and replaces (or pays for) the heating value of the NGLs and the natural gas used during processing. The gatherer/processor is effectively compensating the producer for the amount of gas used/removed during processing by supplying replacement gas, or by paying an agreed-upon value for the amount of gas used/removed. These arrangements entail the highest direct commodity price risk for the gatherer/processor because its costs are dependent on the price of natural gas and its revenues are dependent on the price of NGLs.

 

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U.S. Natural Gas Fundamentals

Natural gas is a critical component of energy consumption in the U.S., accounting for approximately 24% of all energy used in 2008, representing approximately 23.3 Tcf of natural gas, according to the U.S. Energy Information Administration (“EIA”). Over the next 27 years, the EIA estimates that total domestic energy consumption will increase by over 15%, with natural gas consumption directly benefiting from population growth, growth in cleaner-burning natural gas-fired electric generation and natural gas vehicles, and indirectly through additions of electric vehicles.

U.S. natural gas consumption is currently satisfied primarily by production from conventional onshore and offshore production in the lower 48 states and is supplemented by production from historically declining pipeline imports from Canada, imports of liquefied natural gas (“LNG”) from foreign sources as well as some production in Alaska. In order to maintain current levels of U.S. natural gas supply and to meet the projected increase in demand, new sources of domestic natural gas must continue to be developed to offset an established trend of depletion associated with mature, conventional production as well as the uncertainty of future LNG imports and infrastructure challenges associated with sourcing additional production from Alaska . Over the past several years, a fundamental shift in production has emerged with the contribution of natural gas from unconventional resources, defined by the EIA as natural gas produced from shale formations and coalbeds, increasing from 9% of total U.S. natural gas supply in 2000 to 15% in 2008. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per unit economics versus most conventional plays.

The U.S. Geological Service, Mineral Management Service and EIA estimate that in 2010 the U.S. possesses over 2,000 Tcf of technically recoverable natural gas resources, an increase of approximately 30% from 2008 estimates of technically recoverable natural gas resources, which is primarily due to technological advancements. As the depletion of onshore conventional and offshore resources continues, natural gas from unconventional resource plays is forecast to fill the void and continue to gain market share from higher-cost sources of natural gas. Natural gas production from the major shale formations is forecast to provide the majority of the growth in unconventional natural gas supply, increasing to approximately 24% of total U.S. natural gas supply in 2035 as compared with 6% in 2008. This represents a projected four-fold increase in natural gas shales’ market share of U.S. natural gas supply. The chart below illustrates the composition of the EIA’s forecasted natural gas production through 2035.

LOGO

 

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Overview of our Barnett Shale Region

The Barnett Shale is among the most significant onshore natural gas fields in North America, the largest in Texas, accounting for approximately 23% of Texas’ natural gas production in 2008 and represents the most developed shale play in the U.S. As depicted below, the Barnett Shale is a Mississippian-age shale located within the Fort Worth Basin across 23 counties of north-central Texas, covering approximately 5,000 square miles. The core area of production is located in Denton, Johnson, Tarrant and Wise Counties, with Chesapeake’s acreage position located primarily in Johnson and Tarrant Counties. These Core and Tier 1 areas are characterized by thicker natural gas bearing zones, which results in high initial production rates. The shale principally occurs at depths of 6,500 feet to 8,500 feet and is bounded by limestone formations both above (Marble Falls) and below (Chappel) the shale.

LOGO

Source: ALL Consulting 2009 (prepared for U.S. Department of Energy report)

As of December 31, 2008, more than 10,000 wells had been drilled in the Barnett Shale, making it the most prominent shale gas play in the U.S. As of December 31, 2008, the Barnett Shale had produced more than 5.0 Tcf of natural gas since 1993. During the nine months ended September 30, 2009 there were more than 230 operators active in the play. As of December 31, 2009, approximately half of all of the shale gas in the U.S. was being produced from the Barnett Shale, and it is expected to continue to be an area of active, widespread drilling. Drilling activity in the Barnett Shale region increased sharply from 2004, when the Railroad Commission of Texas issued 1,112 drilling permits, through 2008, when it issued 4,145 permits. However, because of weak economic and natural gas market fundamentals, the number of drilling permits issued in the area in 2009 decreased substantially, with only 1,573 new permits issued through October 2009.

Modern drilling and completion technologies, such as horizontal drilling and large-volume hydraulic fracturing, were first tested and proved commercial in the Barnett Shale. Over time, Chesapeake has increased the productivity of its drilling operations in the Barnett Shale and has drilled wells with longer horizontal laterals in fewer drilling days. While producers continue to expand their drilling operations in the Barnett Shale, operators are expected to focus more on infill drilling going forward in order to maximize the amount of natural gas recovered from existing leases.

 

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LOGO

Source: Railroad Commission of Texas

The location of Barnett Shale in the Dallas-Fort Worth, Texas metropolitan area poses unique challenges associated with drilling for natural gas in urban and suburban communities. State and local regulations regarding the operation of drilling rigs limit the number of potential new drilling sites that can be used for infill drilling programs. Infill drilling is expected to principally occur on existing drilling pads and/or connect to established gathering systems given the challenges of establishing new gathering systems in the urban environment. An established footprint and the use of multi-well drilling pads provides a competitive advantage to current gatherers, providing opportunity to leverage prior capital expenditures.

Overview of our Mid-Continent Region

Our Mid-Continent region, which we define as the geographic area containing our midstream operations in Oklahoma, Texas (excluding the Barnett Shale region), Arkansas, New Mexico and Kansas, is primarily characterized by the ongoing development of the Anadarko Basin and the Permian Basin. The development of the Mid-Continent region was initially driven by the demand for oil in the early 20th century, and many of the resource plays in the region have been producing oil and natural gas for decades. More recently, natural gas production has become more prominent in areas where oil was historically the focus. For example, in Oklahoma, over 90% of the drilling rigs operating as of February 5, 2010 were focused on developing natural gas reserves. In particular, natural gas producers have been targeting the unconventional resources in the Mid-Continent region, such as the wash, shale gas, tight sands and coalbed methane plays in the Anadarko, Arkoma, Delaware and Permian Basins. Increased exploration and the application of horizontal drilling and multi-stage fracturing technology in the area has recently yielded new unconventional resource plays with revitalized production growth and improved well economics, such as the Colony Granite Wash and Texas Panhandle Granite Wash plays in the Anadarko Basin. The recent development of unconventional resource plays has brought renewed focus on the region from producers who had once viewed the region as a developed production area with limited growth potential. Chesapeake has established itself as a leader in developing unconventional resources in the Mid-Continent region and, as such, has drilled more horizontal wells in the Granite Wash than any other operator.

Conventional production from the Anadarko Basin has historically provided most of the growth in natural gas production from the Mid-Continent region. As conventional production from the Anadarko Basin has declined, however, the tight gas formations of the Colony Granite Wash and Texas Panhandle Granite Wash plays have become increasingly important sources of new volumes. The Colony Granite Wash and Texas Panhandle Granite Wash plays span an estimated 1,180 square miles across western Oklahoma (Caddo, Custer, Roger Mills, Beckham and Washita Counties) as well as the northeastern portion of the Texas Panhandle (Roberts, Hemphill and Wheeler Counties). These plays are comprised of a series of stacked sandstone pay zones that can be up to 3,500 feet thick. Operators have applied their horizontal drilling experience in other unconventional plays to the Colony Granite Wash and Texas Panhandle Granite Wash, enabling the achievement of initial production rates that are comparable to those of the major U.S. natural gas shale plays. As new horizontal drilling and multi-stage fracturing techniques

 

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continue to improve, unconventional plays are expected to offer an opportunity for Mid-Continent region producers to increase natural gas production in areas where they are already familiar with the geology and, in many cases, have long operating histories. In some locations, these technologies have already improved recovery levels to the point where the economics of these unconventional wells from tight gas formations are comparable to those of shale gas wells, which are expected to be the single most important contributor to natural gas supply growth. To the extent that wells in the Colony Granite Wash and Texas Panhandle Granite Wash plays can achieve similar economics, they may compete along with shale gas and other unconventional sources for increased supply shares .

 

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BUSINESS

Our Partnership

We are a limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts. Our gathering systems operate in our Barnett Shale region in north-central Texas and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service more than 1,500 wells in the core of the prolific Barnett Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. Our systems consist of approximately 2,810 miles of gathering pipelines, servicing over 3,500 natural gas wells. For the nine months ended September 30, 2009, our assets gathered approximately 1.5 Bcf of natural gas per day, ranking us among the largest natural gas gatherers in the U.S.

Our gas gathering systems primarily collect natural gas from unconventional resource plays, a growing source of U.S. natural gas supply that is generally characterized by low finding and development costs compared to conventional resource plays. These systems were historically operated by Chesapeake and are integral to Chesapeake’s operations in our Barnett Shale and Mid-Continent regions. Chesapeake is the second largest natural gas producer in the U.S. by volume of natural gas produced, the most active driller for natural gas in the U.S. by number of drilling rigs utilized and has built a leading unconventional resource base, including in the Barnett Shale and Mid-Continent areas served by our gathering systems, as well as in the Haynesville, Fayetteville and Marcellus shales served by gathering systems owned by Chesapeake. We believe that we have the opportunity to expand our position as a leading gatherer of natural gas from unconventional resource plays because of (i) our substantial current midstream asset base in unconventional resource plays, (ii) our relationship with Chesapeake, which has significant midstream operations in other unconventional resource plays, and (iii) the contractual rights included in our long-term gas gathering and omnibus agreements, including our right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation.

We believe our limited exposure to direct commodity price risk, long-term contractual cash flow stability and conservative capital structure differentiate our business model. We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts that limit our direct commodity price exposure. We have entered into 20-year natural gas gathering agreements with Chesapeake and Total, Chesapeake’s upstream joint venture partner in our Barnett Shale region. On January 25, 2010, Chesapeake closed its $2.25 billion Barnett Shale upstream joint venture arrangement with Total under which Total acquired a 25% non-operated interest in Chesapeake’s Barnett Shale acreage in exchange for a cash payment of $800 million and its agreement to provide funding for $1.45 billion of future drilling and completion expenditures. Total S.A. is the fifth largest integrated oil and gas company in the world based on market capitalization. Chesapeake expects to increase its operated rig count in our Barnett Shale acreage dedication as a result of this joint venture by more than 40% relative to fourth quarter 2009 levels.

Pursuant to our 20-year gas gathering agreements, Chesapeake and Total have agreed to provide us with extensive acreage dedications in our Barnett Shale region and, with respect to our agreement with Chesapeake, our Mid-Continent region. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows:

 

   

10-year minimum volume commitments in our Barnett Shale region, which mitigate throughput volume variability;

 

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fee redetermination mechanisms in our Barnett Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and

 

   

price escalators in our Barnett Shale and Mid-Continent regions, which annually increase our gathering rates.

We believe that the combination of our fixed-fee business model and these contractual protections provide us with long-term cash flow stability and a strong platform from which to grow our business. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

We intend to leverage our relationship with Chesapeake to pursue a growth strategy of increasing throughput on our existing assets, developing new midstream assets to support Chesapeake, Total and other producers, and selectively acquiring midstream assets from Chesapeake and third parties. In addition to the gathering systems already contributed to us in connection with our formation, Chesapeake owns and operates gathering systems outside our current areas of operation in, among other areas, the three other major U.S. shale plays: the Haynesville Shale in northwestern Louisiana and east Texas; the Fayetteville Shale in central Arkansas; and the Marcellus Shale in Pennsylvania, West Virginia and New York. Chesapeake’s expanding midstream asset base in these areas supports its leading acreage positions and consists of approximately 1,500 miles of gathering pipelines that gathered approximately 0.7 Bcf of natural gas per day for the three months ended September 30, 2009. Chesapeake’s remaining midstream businesses including those in the Haynesville, Fayetteville and Marcellus shales represent a significant potential growth opportunity for us. Under our omnibus agreement with Chesapeake, subject to certain exceptions, we have a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation, although Chesapeake will not be obligated to accept any offer we make. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Our Assets and Areas of Operation

We generated approximately 73% of our revenues from our gathering systems in our Barnett Shale region and approximately 27% of our revenues from our gathering systems in our Mid-Continent region for the nine months ended September 30, 2009. The following table summarizes our average daily throughput and our assets by region as of and for the nine months ended September 30, 2009:

 

Region  

Location

(State(s))

  Average
Throughput

(MMcf/d)
  Approximate
Length

(Miles)
  Approximate
Number of
Wells Serviced
  Gas Compression
(Horsepower) (1)

Barnett Shale

  TX   909   700   1,534   128,085

Mid-Continent

  TX, OK, NM, KS, AR   623   2,110   1,984   86,631
                 

Total

    1,532   2,810   3,518   214,716
                 

 

(1) Substantially all of our gas compression is provided by compression equipment leased from Chesapeake. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Compressor Master Rental and Servicing Agreement.”

Barnett Shale Region . The Barnett Shale is among the most significant onshore natural gas fields in North America and the largest in Texas, accounting for approximately 23% of all natural gas produced in Texas in 2008. Our acreage dedication from Chesapeake and Total in the Barnett Shale region is located primarily in Johnson and Tarrant Counties, Texas and is entirely within the Core and Tier 1 portions of the play, which are characterized by thicker natural gas bearing zones, resulting in higher initial production rates. Within the Core

 

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and Tier 1 areas of the Barnett Shale, the Chesapeake-Total joint venture holds more acreage under lease, and Chesapeake has produced more natural gas and drilled more wells, than any other producer. We believe that the relatively low finding and development costs associated with drilling in the Barnett Shale will lead to extensive future development, and we estimate an inventory of more than 4,000 potential gross drilling locations are within our dedicated acreage. For the nine months ended September 30, 2009, our Barnett Shale region gathering volumes averaged 909 MMcf/d.

The nature of the Barnett Shale formation and the engineering, design and construction specifications of our infrastructure should enable us to expand and leverage our existing systems to capture additional natural gas volumes with relatively low incremental capital expenditures. Because of the high initial production rates of most Barnett Shale wells, our gathering systems are generally designed to accommodate high initial volumes, which should enable us to accommodate additional volumes as initial high production rates decline and the development of additional Barnett Shale wells continues. Furthermore, since Chesapeake typically drills one to three wells from a drilling pad that will ultimately accommodate six to seven total wells, we estimate that our systems are already connected to the majority of the multi-well drilling pads that Chesapeake believes are required to fully develop its leaseholds within our dedicated acreage. In addition, we have completed the majority of our larger diameter, “trunkline” infrastructure, and as a result, we are well-positioned to leverage our previous capital investment as additional gathering pipelines are connected to our trunkline infrastructure. Given the size and scale of our system, as well as the barriers to entry created by the significant capital investment required to construct gathering infrastructure in the urban and suburban Dallas-Fort Worth Metropolitan area, we believe our geographic footprint provides us with a competitive advantage in gathering future volumes from Chesapeake and third parties.

Mid-Continent Region . The Mid-Continent region, broadly defined, traces its development to oil drilling in the early 20th century and has been a source of U.S. natural gas supply for decades. More recently, natural gas producers have been targeting unconventional resources in the Mid-Continent, such as the wash, shale gas, tight sands and coalbed methane plays in the Anadarko, Arkoma, Delaware and Permian Basins. Increased exploration and the application of horizontal drilling and multi-stage fracturing technology in the area has recently yielded new unconventional resource plays with revitalized production growth and improved well economics.

We define our Mid-Continent region as the geographic area containing our midstream operations in Oklahoma, Texas (excluding the Barnett Shale), Arkansas (excluding the Fayetteville Shale), New Mexico and Kansas. Within our Mid-Continent region, Chesapeake has dedicated to us the right to gather natural gas produced from all owned or operated wells that it drills within two miles in any direction of our gathering systems existing at September 30, 2009. In the aggregate, this dedication includes over 2 million gross acres in 67 counties. Chesapeake’s most active development in the Mid-Continent region is focused on high-growth, unconventional resource plays within the Anadarko and Permian Basins, and the balance of our gathering systems in the region service developed production characterized by low decline rates. In particular, Chesapeake believes that the unconventional Colony Granite Wash and Texas Panhandle Granite Wash plays currently represent three of its most attractive prospective Mid-Continent growth opportunities. For the nine months ended September 30, 2009, our Mid-Continent region gathering volumes averaged approximately 623 MMcf/d.

Our Business Strategies

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business. We expect to achieve this objective through the following strategies:

 

   

Focus on High-Growth, Unconventional Plays . We are principally focused on natural gas gathering opportunities in our Barnett Shale region and several unconventional resource plays in our Mid-Continent region, including the Colony Granite Wash and Texas Panhandle Granite Wash plays, that we believe are cost-advantaged sources of natural gas supply and are positioned for continued significant production growth. The Barnett Shale and Chesapeake’s unconventional operations in the Anadarko and Permian Basins are generally characterized by low finding and development costs and

 

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high drilling success rates compared to most conventional resource plays, and Chesapeake is among the leading producers in these areas. Our gathering systems in these areas collectively accounted for approximately 65% of our average daily throughput during the nine months ended September 30, 2009. We expect that our future midstream development initiatives will likewise focus on unconventional resource plays where favorable well economics should lead to increased natural gas production even in challenging commodity price environments. The combination of our extensive operations in these areas and our relationship with Chesapeake, the second largest natural gas producer and the leading leasehold owner in U.S. in unconventional resource plays, provides us the opportunity to become the leading natural gas gatherer from unconventional resource plays in the U.S.

 

   

Leverage Our Extensive Asset Base . We own and operate a high-quality, high-capacity asset base that provides us with the opportunity to significantly increase volumes from Chesapeake, Total and other third-party producers across our existing systems. We have invested significant capital constructing gathering infrastructure comprised of high tensile strength, large diameter steel pipelines that are engineered and constructed to accommodate meaningful additional natural gas volumes. As Chesapeake, Total and other producers execute their ongoing drilling plans within our areas of operation, we are positioned to leverage existing high quality systems and historical capital expenditures to accommodate the additional natural gas volumes. In the Barnett Shale, for example, we estimate that the majority of the multi-well drilling pads required to fully develop the current acreage of the Chesapeake-Total joint venture are already connected to our existing gathering systems while more than 4,000 potential gross drilling locations remain in inventory. As additional wells are drilled from these connected pads, our systems will capture significant incremental volumes with relatively low incremental cost primarily in the form of additional compression. Furthermore, as our relationship with Chesapeake provides us with visibility on its future drilling initiatives, we will seek to optimize our existing systems by adding to our third-party volumes in areas where we expect to have available capacity.

 

   

Minimize Direct Commodity Price Exposure . Our business model seeks to minimize direct commodity price exposure and promote cash flow stability. We currently generate substantially all of our revenues pursuant to long-term, fixed-fee contracts, and we plan to maintain our focus on fixed-fee services as we grow our business. We generally plan to avoid activities that would subject us to direct commodity price exposure. In addition to our fixed-fee contract structure, we have reduced our exposure to fluctuations in volumes and revenues that may occur during periods of low natural gas prices and reduced drilling through our long-term gas gathering agreements with Chesapeake and Total, which contain several contractual provisions that are designed to support the stability of our cash flows in the event of lower than expected volumes, subject to certain limitations.

 

   

Grow Through Disciplined Development and Accretive Acquisitions . We plan to selectively pursue accretive acquisitions of developed midstream assets from Chesapeake and other parties and to pursue organic development that will complement and expand our existing operations. Our omnibus agreement provides us a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation. We believe that we are also well-positioned to pursue midstream acquisition opportunities from third parties, both because of the network of relationships enjoyed by our experienced management team and as a result of our extensive asset footprint, particularly in the Barnett Shale.

Our Competitive Strengths

We believe that we will be able to successfully execute our business strategies because of the following competitive strengths:

 

   

Well-Positioned Asset Base . Our gathering systems include extensive high-quality natural gas pipeline networks in our Barnett Shale and Mid-Continent regions, which include high-growth unconventional resource plays in the Anadarko Basin, such as the Colony Granite Wash and Texas Panhandle Granite Wash plays. Chesapeake has increased production 53% in these areas over the past year and they

 

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have been targeted by Chesapeake for significant future drilling activity because of their significant resource potential and low finding and development costs compared to most conventional resource plays, estimated by Chesapeake to be less than $1.50 per Mcf. For example, the Barnett Shale is among the largest natural gas fields in North America and is the largest in Texas, accounting for approximately 23% of Texas’ natural gas production in 2008. Similarly, the Anadarko Basin has historically produced the majority of natural gas in the Mid-Continent region and is projected to grow at an accelerated pace through the application of horizontal drilling and multi-stage fracturing technologies. These unconventional resource plays represent an increasingly important source of U.S. natural gas supply, and we expect them to continue to be growth areas for Chesapeake and other producers. We believe that our geographically advantaged asset footprint, the scale of our systems and our expertise in gathering from unconventional resource plays, including developing energy infrastructure in urban and suburban environments, will enable us to expand our position as a leading gatherer of natural gas from unconventional resource plays.

 

   

Extensive Acreage Dedication and System Scale . We have significant embedded volume growth potential associated with our extensive acreage dedication that Chesapeake and Total have committed to us in our Barnett Shale region and that Chesapeake has committed to us in the Mid-Continent region pursuant to our 20-year gas gathering agreements as well as the significant scale of our existing gathering systems. We estimate that the areas covered by our acreage dedications include more than 4,000 and 6,000 potential gross drilling locations in our Barnett Shale and Mid-Continent regions, respectively. We expect increased throughput across our systems as the Chesapeake-Total joint venture pursues its drilling program in our Barnett Shale region and Chesapeake continues its drilling program in our Mid-Continent region. Most of our gathering systems have been engineered and constructed to accommodate significant additional natural gas volumes, and we expect to be able to optimize our systems by connecting receipt points and attracting third-party volumes.

 

   

Long-Term Contracted Cash Flow Stability . We believe that our business model, including our fixed-fee contract structure and long-term gas gathering agreements, mitigates our exposure to direct commodity price risk and provides us with long-term cash flow stability. We have entered into long-term gas gathering agreements with Chesapeake and Total that include minimum volume commitments, periodic fee redeterminations and other contractual provisions that are intended to support cash flow stability and growth. Our 10-year minimum volume commitments from Chesapeake and Total in our Barnett Shale region mitigate throughput volume variability from drilling and well production. Similarly, the fee redetermination provisions applicable to our Barnett Shale and Mid-Continent operations were designed to support a return on our invested capital and allow our gathering rates to account for variability in our revenues, capital expenditures and compression expenses. In addition, our contracts with Chesapeake and Total provide embedded annual growth in volumes and annual fee escalators. We have also entered a long-term contract for our compression requirements, the largest single component of our operating expenses, which further enhances the stability of our cash flows by allowing us to lease compression under a fixed fee structure through September 30, 2016.

 

   

Relationship with Chesapeake . Our relationship with Chesapeake, the industry’s leader in unconventional natural gas drilling and production with leading positions in the Haynesville, Fayetteville and Marcellus shale plays in addition to its operations in our Barnett Shale and Mid-Continent regions, provides us with significant potential long-term growth opportunities. In addition to our support of Chesapeake’s key upstream operations in our Barnett Shale and Mid-Continent regions, Chesapeake is incentivized to grow our business because of its 50% ownership interest in our general partner, 50% ownership in the incentive distribution rights and     % ownership in our common units at the closing of this offering. Additionally, our omnibus agreement provides us a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities within five miles of our acreage dedications.

 

   

Experienced Midstream Management Team . Our senior officers have significant experience building, acquiring and managing midstream or other assets and will be focused on optimizing our existing

 

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business and expanding our operations through disciplined development and accretive acquisitions. J. Mike Stice, the chief executive officer of our general partner, has over 28 years of experience constructing and operating developed midstream infrastructure for ConocoPhillips, where he was most recently charged with developing significant natural gas liquefaction and regasification projects and was previously president of Gas & Power for Conoco. In addition, he was a key leader within the ConocoPhillips midstream organization that ultimately developed into DCP Midstream. Robert S. Purgason, the chief operating officer of our general partner, has over 30 years of experience acquiring and operating midstream energy assets, first for The Williams Companies and more recently for Crosstex Energy, where he led operations and commercial development activities. David Shiels, the chief financial officer of our general partner, has over 21 years of financial planning and analysis experience with General Electric and Conoco, where he was most recently the chief financial officer of GE Security Americas.

 

   

Conservative Capital Structure . We believe that our conservative capital structure will allow us to pursue organic growth opportunities and acquisitions even in challenging commodity price environments and periods of capital markets dislocation. At the closing of this offering, we expect to enter into a $500 million syndicated revolving credit facility that will mature in 2012 and provide us with financial flexibility to fund capital projects independent of conditions in the capital markets. At the closing of this offering and after using the net proceeds therefrom in the manner described in “Use of Proceeds,” we expect to have no outstanding indebtedness and $             million of liquidity in the form of cash on hand and undrawn borrowing capacity under our revolving credit facility, providing us with substantial financial flexibility.

Our Relationship with Chesapeake

One of our principal strengths is our relationship with Chesapeake. Chesapeake is the second largest natural gas producer in the U.S. by volume of natural gas produced and is the most active driller for natural gas in the U.S. by number of drilling rigs utilized. As of September 30, 2009, Chesapeake owned interests in approximately 43,600 producing natural gas and oil wells, which produced approximately 2.4 Bcfe per day for the nine months ended September 30, 2009, 92% of which was natural gas. Chesapeake’s primary strategy focuses on discovering, acquiring and developing conventional and unconventional natural gas reserves onshore in the U.S., primarily in the “Big Four” natural gas shale plays: the Barnett Shale, the Haynesville Shale, the Fayetteville Shale and the Marcellus Shale. Chesapeake also has substantial operations in various other established and developing plays, both conventional and unconventional.

At the closing of this offering, Chesapeake will indirectly own both 50% of our general partner and our incentive distribution rights through its ownership in Chesapeake Midstream Ventures. Chesapeake will also directly own an aggregate     % limited partner interest in us through its ownership of              common units and              subordinated units. Because of its disproportionate participation in any increases to our cash distributions through the incentive distribution rights, Chesapeake is positioned to directly benefit from dedicating additional natural gas volumes to our systems and facilitating organic growth opportunities and accretive acquisitions from itself or third parties. In addition, under our omnibus agreement, subject to certain exceptions, we have a right of first offer on future Chesapeake midstream divestitures as well as development and acquisition opportunities adjacent to our existing areas of operation, although Chesapeake will not be obligated to accept any offer we make. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.”

Chesapeake’s designees to the board of directors of our general partner will be Aubrey K. McClendon, Chesapeake’s Chairman and Chief Executive Officer, and Marcus C. Rowland, Chesapeake’s Executive Vice President and Chief Financial Officer. We believe that these directors will provide us with superior insights into natural gas production dynamics, financial management, the capital markets and merger and acquisition opportunities.

 

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Given our focus on gathering natural gas from unconventional resource plays, we believe that our relationship with Chesapeake is advantageous for the following reasons:

 

   

Chesapeake Is a Leader in Unconventional Natural Gas Technology and Production . Chesapeake has been developing expertise in horizontal drilling technology since shortly after its inception in 1989 and was one of the first companies to recognize the potential of unconventional natural gas resource plays in the U.S. During the past five years, Chesapeake has grown from the eighth largest natural gas producer in the U.S. to the second largest natural gas producer, measured by natural gas volumes produced, in large part as a result of its success in finding and developing unconventional natural gas assets. Chesapeake currently maintains an active drilling program and the largest leasehold position in the U.S. “Big Four” natural gas shale plays (5.3 million gross acres, of which less than 10% have been dedicated to us).

 

   

Our Operating Areas Are Core Growth Areas for Chesapeake . The natural gas gathered by our systems in our Barnett Shale and Mid-Continent regions represented approximately 38% and 26%, respectively, of Chesapeake’s total natural gas production during the nine months ended September 30, 2009. Chesapeake’s undeveloped reserves within these regions provide us with significant organic growth opportunities. Pursuant to their joint venture arrangement, Chesapeake and Total hold an aggregate approximate 400,000 gross acres in the greater Barnett Shale area as of January 2010, and Chesapeake expects to increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth quarter 2009 levels.

 

   

Gas Gathering Agreements . We have entered into 20-year natural gas gathering agreements with Chesapeake and Total pursuant to which Chesapeake and Total have agreed to provide us with acreage dedications within our Barnett Shale region and, with respect to our agreement with Chesapeake, our Mid-Continent region. These agreements include 10-year minimum volume commitments covering Barnett Shale region production and a periodic fee redetermination mechanism to account for variability in revenues, capital expenditure requirements and compression expenses in our Barnett Shale region with Chesapeake and Total and, with respect to our Mid-Continent region, with Chesapeake. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

Our Relationship with GIP

At the closing of this offering, GIP will indirectly own 50% of both our general partner and our incentive distribution rights through its ownership in Chesapeake Midstream Ventures. GIP will also directly own an aggregate     % limited partner interest in us through its ownership of              common units and              subordinated units.

GIP is a $5.6 billion independent infrastructure investment fund with offices in New York, London, Hong Kong and Stamford, Connecticut and an affiliated office in Sydney. GIP focuses on investments in three core sectors: energy, transportation, and water/waste. GIP’s global team possesses deep experience in its target infrastructure sectors, operations and finance. Affiliates of Credit Suisse Group AG and General Electric Company were, along with GIP’s partners, founding investors of GIP. GIP’s interests in the energy sector include, among others, a 50/50 joint venture interest with El Paso Corporation in the 1.5 Bcf per day Ruby interstate pipeline project (under advanced development); Channelview, an 800 megawatt gas-fired cogeneration project in Texas; and a joint venture interest with ArcLight Capital Partners in Terra-Gen, one of the leading renewable power generation companies in the U.S.

GIP’s designees to the board of directors of our general partner will be Matthew C. Harris, a GIP partner and former Co-Head of Energy Investment Banking at Credit Suisse, and William A. Woodburn, a GIP partner and former President and Chief Executive Officer of GE Infrastructure. We believe that these directors will provide us with superior insights into the capital markets, merger and acquisitions opportunities, process management and productivity optimization.

 

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Chesapeake—Total Joint Venture

On January 25, 2010, Chesapeake closed its $2.25 billion Barnett Shale upstream joint venture arrangement with Total pursuant to which Total acquired a 25% non-operated interest in Chesapeake’s Barnett Shale acreage in exchange for a cash payment of $800 million and its agreement to provide funding for $1.45 billion of future drilling and completion expenditures. In connection with the closing of the joint venture, Chesapeake MLP Operating, L.L.C. entered into a 20-year gas gathering agreement with Total on substantially similar terms to our gas gathering agreement with Chesapeake. Under this agreement, Total will provide us with, among other things, 10-year volume commitments within the Barnett Shale region equal to an approximate 25% of the aggregate volumes committed to us by Chesapeake and Total in the Barnett Shale region. Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements” and “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.”

We believe that the Chesapeake-Total joint venture will be beneficial to us for the following reasons:

 

   

Anticipated Increase in Barnett Shale Drilling . Under the Chesapeake-Total joint venture arrangement, Total provided Chesapeake with an $800 million up-front cash payment and is required to fund $1.45 billion of future drilling and completion expenditures in the Barnett Shale. Chesapeake anticipates that this $1.45 billion funding will occur prior to December 31, 2012. Accordingly, Chesapeake expects to increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total by more than 40% relative to fourth quarter 2009 levels. We believe that this increase in drilling activity will result in additional volumes being transported through systems in our Barnett Shale region.

 

   

Strong Additional Major Customer . By partnering with Total, the fifth largest integrated oil and natural gas company in the world based on market capitalization, we believe that Chesapeake will be well-positioned to execute its strategy of increasing production within the Barnett Shale region. Additionally, we believe that our gas gathering agreement with Total will provide us with a strong additional major customer in the Barnett Shale region. Pursuant to its gas gathering agreement with us, Total will be subject to a volume commitment equal to approximately 25% of the aggregate volumes committed to us by Chesapeake and Total in the Barnett Shale region.

Our Assets

Our assets primarily consist of natural gas gathering pipelines and treating facilities. These assets are located in five states and are divided into two operating regions:

 

   

Barnett Shale Region . Our gathering systems in the Barnett Shale region are primarily located in Tarrant, Johnson and Dallas counties in Texas in the Core and Tier 1 areas of the Barnett Shale. These Core and Tier 1 areas are characterized by thicker natural gas bearing geological zones, which results in higher initial production rates. Typically, gas produced in Core and Tier 1 areas is characterized as “lean” and needs little to no treatment to remove contaminants. Our Barnett Shale gathering systems are comprised of approximately 700 miles of gathering pipelines with over 900 MMcf of daily throughput using over 128,000 horsepower of compression.

 

   

Mid-Continent Region . Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas (excluding the Barnett Shale), Arkansas, New Mexico and Kansas and are comprised of approximately 2,110 miles of gathering pipelines and treatment facilities with over 620 MMcf of daily throughput. Included in our Mid-Continent region are three treating facilities located in Beckham and Grady Counties, Oklahoma and Reeves County, Texas that are designed to remove contaminants from the natural gas stream.

Our Barnett Shale and Mid-Continent region systems are comprised of high-quality infrastructure designed to gather, treat and compress natural gas produced by Chesapeake, Total and their working interest partners for

 

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delivery to major intrastate and interstate pipelines. We have approximately 3,725 receipt points where gas is transferred from the producer’s wellhead or gathering pipeline to our gathering systems. We receive natural gas from individual wells, as well as from central receipt points for multiple wells, such as pad level meters and producer gathering systems. Chesapeake, Total and their working interest partners are our primary customers in both the Barnett Shale and Mid-Continent regions. While we believe our relationship with Chesapeake provides us with competitive advantages, we are not restricted from gathering third-party volumes on our systems. Accordingly, we intend to attract additional third-party volumes over time by providing high-quality midstream services.

Barnett Shale Region

General . Chesapeake commenced operations in this area in December 2004 after it acquired properties and assets from Hallwood Energy. These assets are located near Cleburne, Texas in Johnson County. Chesapeake purchased additional assets in July 2005 and, in September 2006, acquired Dale Gas Partners, significantly increasing its position in Tarrant and western Dallas Counties. Since Chesapeake’s acquisition of the Hallwood Energy gathering system and Dale Gas Partners, it has significantly grown the Barnett Shale system, which now consists of 18 interconnected gathering systems and approximately 700 miles of pipeline.

Our assets in the Barnett Shale region have been designed and developed to accommodate their urban setting in and around the greater Dallas-Fort Worth, Texas metropolitan area. Average throughput on our Barnett Shale gathering systems for the year ended December 31, 2008 and the nine months ended September 30, 2009 was 707 MMcf/d and 909 MMcf/d, respectively, from approximately 1,200 and 1,500 receipt points, respectively. We connect our gathering systems to receipt points that are either at the individual wellhead or at central receipt points into which production from multiple wells are gathered. Due to Chesapeake’s practice of drilling multiple wells on an individual drilling pad, a significant number of our receipt points in the Barnett Shale collect production from multiple producing wells. Our Barnett Shale system has pipeline diameters ranging from four-inch well connection lines to 24-inch major trunk lines and is connected to 24 compressor stations providing over a combined 128,000 horsepower of compression.

Supply . Chesapeake is the second largest producer, the most active driller and largest leaseholder in the greater Barnett Shale area. As of September 30, 2009, Chesapeake has produced in excess of 500 Bcf of natural gas, drilled over 1,800 gross wells and currently controls approximately 400,000 gross acres. For the last three years, Chesapeake has maintained an active drilling program in the Barnett Shale region, utilizing between 15 and 40 drilling rigs to drill an average of 475 wells per year. We believe that the relatively low finding and development costs associated with drilling in the Barnett Shale compared to conventional resource plays will lead to extensive future development , and we estimate this area has an inventory of more than 4,000 potential gross drilling locations. We estimate that we have connected the majority of the multi-well drilling pads required to fully develop our dedicated acreage.

Delivery Points . Our Barnett Shale gathering system is connected to the following downstream transportation pipelines:

 

   

Atmos Pipeline Texas —gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and south, east and west Texas markets at the Katy, Carthage and Waha hubs;

 

   

Energy Transfer Pipeline Texas —gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Midcontinent Express Pipeline, Centerpoint CP Expansion Pipeline and Gulf South 42” Expansion Pipeline; and

 

   

Enterprise Texas Pipeline —gas delivered into this pipeline system serves the greater Dallas/Fort Worth metropolitan area and southeastern and northeastern U.S. markets supplied by the Gulf Crossing Pipeline.

 

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Mid-Continent Region

Anadarko Basin and Northwest Oklahoma

General . Our assets within the Anadarko Basin and Northwest Oklahoma region are located in northwestern Oklahoma and the northeastern portion of the Texas Panhandle and consist of approximately 1,250 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the year ended December 31, 2008 and the nine months ended September 30, 2009 of 286 MMcf/d and 313 MMcf/d, respectively, from approximately 1,100 and over 1,200 receipt points, respectively. These systems are connected to 24 compressor stations providing a combined approximate 46,000 horsepower of compression.

Within the Anadarko Basin, we are primarily focused on servicing Chesapeake’s production from the Colony Granite Wash and Texas Panhandle Granite Wash plays. Natural gas production from these areas of the Anadarko Basin typically contains significant amounts of NGLs and requires processing prior to delivery to end-markets. In addition, we operate an amine treater with sulfur removal capabilities at our Mayfield facility in Beckham County, Oklahoma. Our Mayfield gathering and treating system primarily gathers Deep Springer natural gas production and treats the natural gas to remove carbon dioxide and hydrogen sulfide to meet the quality specifications of downstream transportation pipelines.

Supply . Chesapeake is the largest producer, the most active driller and largest leaseholder in the areas served by our Anadarko Basin and Northwest Oklahoma region gathering systems. As of September 30, 2009, Chesapeake has produced in excess of 775 Bcf of natural gas and controls approximately 1.3 million gross acres in the area served by our Anadarko Basin and Northwest Oklahoma region gathering systems. For the nine months ended September 30, 2009, Chesapeake produced approximately 360 gross MMcf/d from over 1,200 gross operated wells. We believe that improved production rates in the Anadarko Basin and Northwest Oklahoma region resulting from the application of drilling technologies developed for unconventional shale gas plays should lead to extensive future development.

Delivery Points . Our Anadarko Basin and Northwest Oklahoma region systems are connected to a significant majority of the major transportation pipelines transporting natural gas out of the region, including pipelines owned by Enbridge and Atlas Pipelines, as well as local market pipelines such as those owned by Enogex. These pipelines provide access to midwest and northeastern U.S. markets as well as intrastate markets.

Permian Basin

General . Our Permian Basin assets are located in west Texas and consist of approximately 310 miles of pipeline across the Permian and Delaware Basins. Average throughput on our gathering systems for the year ended December 31, 2008 and the nine months ended September 30, 2009 was 121 MMcf/d and 102 MMcf/d, respectively, from approximately 235 and 255 receipt points, respectively. The systems have pipeline diameters ranging from 4 inches to 16 inches and are connected to 11 compressor stations providing a combined approximate 14,190 horsepower of compression.

Supply . Chesapeake is the largest producer, the most active driller and largest leaseholder in areas served by our Permian Basin gathering systems. As of September 30, 2009, Chesapeake has produced in excess of 150 Bcf of natural gas and controls approximately 470,000 gross acres in the areas served by our Permian Basin gathering systems.

Delivery Points . Our Permian Basin gathering systems are connected to pipelines in the area owned by Southern Union, Enterprise, West Texas Gas, DCP Midstream and Regency. Natural gas delivered into these transportation pipelines is re-delivered into the Waha Hub and El Paso Gas Transmission. The Waha Hub serves the Texas intra-state electric power plants and heating market, as well as the Houston Ship Channel chemical and refining markets. El Paso Gas Transmission serves western U.S. markets.

 

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Other Mid-Continent Region

Our Other Mid-Continent region assets consist of systems in the Ardmore Basin in Oklahoma, the Arkoma Basin in eastern Oklahoma and western Arkansas and the East Texas region and the Gulf Coast region of Texas. The Other Mid-Continent region assets include approximately 550 miles of pipeline. These gathering systems are generally localized systems gathering specific production for re-delivery into established pipeline markets. Average throughput on these gathering systems for the year ended December 31, 2008 and the nine months ended September 30, 2009 was 200 MMcf/d and 208 MMcf/d, respectively, from approximately 707 and 728 receipt points, respectively. The systems have pipeline diameters ranging from 4 inches to 24 inches and are connected to 27 compressor stations providing a combined approximate 26,400 horsepower of compression.

Competition

Given that substantially all of the natural gas gathered and transported through our systems is owned by Chesapeake, Total and their working interest partners within our acreage dedications, we do not currently face significant competition for our natural gas volumes. In addition, Chesapeake and Total have dedicated all of their natural gas produced from existing and future wells located on lands within our acreage dedication in the Barnett Shale region and Chesapeake has made a similar dedication in our Mid-Continent region.

In the future, we may face competition for Chesapeake’s production drilled outside of our acreage dedication and in attracting third-party volumes to our systems. Additionally, to the extent we make acquisitions from third parties we could face incremental competition. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures and fuel efficiencies. We currently anticipate that our competitors in our Barnett Shale region would include Energy Transfer Partners, Crosstex Energy, Quicksilver Gas Services, Freedom Pipeline, Peregrine Pipeline, XTO Energy, EOG Resources, DFW Mid-Stream and Enbridge Energy Partners. We currently anticipate that our competitors in our Mid-Continent region would include Enogex, Atlas Pipeline Partners and DCP Midstream.

Safety and Maintenance

We are subject to regulation by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, of the Department of Transportation, or the DOT, pursuant to the Natural Gas Pipeline Safety Act of 1968, or the NGPSA, and the Pipeline Safety Improvement Act of 2002, or the PSIA, which was reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of gas pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. oil and natural gas transportation pipelines and some gathering lines in high-consequence areas. The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways.

We or the entities in which we own an interest inspect our pipelines regularly using equipment rented from third-party suppliers. Third parties also assist us in interpreting the results of the inspections.

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our natural gas pipelines have continuous inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

 

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In addition, we are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency, or EPA, community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above the specified thresholds or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling points without the benefit of chilling or refrigeration are exempt. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

Regulation of Operations

Natural gas gathering and intrastate transportation facilities are exempt from the jurisdiction of FERC under the Natural Gas Act. Although FERC has not made any formal determinations respecting any of our facilities, we believe that our natural gas pipelines and related facilities are engaged in exempt gathering and intrastate transportation and, therefore, not subject to FERC jurisdiction. However, FERC regulation still affects our gathering and compression business. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open access transportation, market manipulation, ratemaking, capacity release and market transparency and market center promotion, directly and indirectly affect our gathering business. In addition, the distinction between FERC-regulated transmission facilities and federally unregulated gathering and intrastate transportation facilities is a fact-based determination made by the FERC on a case by case basis; this distinction has also been the subject of regular litigation and change. The classification and regulation of our gathering and intrastate transportation facilities are subject to change based on future determinations by FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided by it are not exempt from FERC regulation, the rates for, and terms and conditions of services provided by such facility would be subject to regulation by the FERC. Such regulation could decrease revenues, increase operating costs, and depending upon the facility in question, could adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of civil penalties as well as a requirement to disgorge charges collected for such service in excess of the cost-based rate established by the FERC.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

 

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Our natural gas gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

During the 2007 legislative session, the Texas State Legislature passed H.B. 3273, or the Competition Bill, and H.B. 1920, or the LUG Bill. The Texas Competition Bill and LUG Bill contain provisions applicable to gathering facilities. The Competition Bill allows the Railroad Commission of Texas, or the TRRC, the ability to use either a cost-of-service method or a market-based method for setting rates for natural gas gathering in formal rate proceedings. It also gives the TRRC specific authority to enforce its statutory duty to prevent discrimination in natural gas gathering, to enforce the requirement that parties participate in an informal complaint process and to punish purchasers, transporters and gatherers for taking discriminatory actions against shippers and sellers. The LUG Bill modifies the informal complaint process at the TRRC with procedures unique to lost and unaccounted for gas issues. It extends the types of information that can be requested and gives the TRRC the authority to make determinations and issue orders in specific situations. Both the Competition Bill and the LUG Bill became effective September 1, 2007. In November 2007, the TRRC initiated rulemaking proceedings to implement the TRRC’s authority pursuant to the LUG Bill and the Competition Bill. At its open meeting on April 8, 2008, the TRRC unanimously adopted the following rules into the Texas Administrative Code: 16 TAC 7.7003 (Administrative Penalties and Other Remedies for Discrimination), 16 TAC 7.7005 (Authority to Set Rates), 16 TAC 2.1 (Informal Complaint Procedure), 16 TAC 2.5 (Informal Complaint Process Regarding Loss of or Inability to Account for Gas), and 16 TAC 2.7 (Administrative Penalties for Failure to Participate), implementing the TRRC’s authority pursuant to the LUG Bill and the Competition Bill. The rules became effective on April 28, 2008. We are unable to predict the effect, if any, these rules might have on our natural gas gathering operations.

Environmental Matters

General

Our operation of pipelines, plants and other facilities for the gathering, treating and compressing of natural gas and other products is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

   

requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;

 

   

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

   

requiring investigatory and remedial actions to limit pollution conditions caused by our operations or attributable to former operations; and

 

   

prohibiting the operations of facilities deemed to be in non-compliance with permits issued pursuant to such environmental laws and regulations.

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 obligations,

 

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and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat and transport natural gas. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of the material environmental laws and regulations that relate to our business. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes, and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, referred to as CERCLA or the Superfund law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include current and prior owners or operators of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although natural gas is not classified as a hazardous substance under CERCLA, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes, that are subject to the requirements of the Resource Conservation and Recovery Act, referred to as RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements relating to the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes

 

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currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We currently own or lease, and our Predecessor has in the past owned or leased, properties where hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. For example, TCEQ and the Railroad Commission of Texas have been evaluating possible additional regulation of air emissions in the Barnett Shale area, in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions against the regulated community. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in substantial compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

Water Discharges

The Federal Water Pollution Control Act, or the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flow.

 

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Hydraulic Fracturing

The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells by our customers, particularly in our Barnett Shale region and the unconventional resource plays in our Mid-Continent Region. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult for our customers to perform hydraulic fracturing and increase our customers’ costs of compliance and doing business. Chesapeake and many other producers make extensive use of hydraulic fracturing in the areas that we serve and any federal, state or local increased regulation could reduce the volumes of natural gas that they move through our gathering systems which would materially adversely affect our revenues and results of operations.

Endangered Species

The Endangered Species Act, or ESA, restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in substantial compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Global Warming and Climate Change

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes. In response to such studies, the U.S. Congress is actively considering legislation to reduce emissions of GHGs. One bill recently approved by the U.S. House of Representatives, known as the American Clean Energy and Security Act of 2009, or ACESA, would require an 80% reduction in emissions of GHGs from sources within the U.S. between 2012 and 2050. Moreover, almost half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations ( e.g. , at compressor stations). Although we would not be impacted to a greater degree than other similarly situated midstream transporters of natural gas, a stringent GHG control program could have an adverse effect on our cost of doing business and could reduce demand for the natural gas we process, gather and treat.

In addition, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment, because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In

 

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anticipation of the endangerment finding being finalized, in late September and early October of 2009 the EPA officially proposed two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which would regulate emissions of GHGs from motor vehicles and the other of which would regulate emissions of GHGs from large stationary sources of emissions such as power plants or industrial facilities. The EPA has indicated that it hopes to adopt final versions of both sets of rules by March 2010. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the U.S., including natural gas liquids fractionators and local natural gas distribution companies, beginning in 2011 for emissions occurring in 2010. Although it may take the EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations.

Anti-Terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security, or DHS, to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk will be required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. We have not yet determined the extent to which our facilities are subject to coverage under the interim rules or the associated costs to comply, but it is possible that such costs could be substantial.

Title to Properties and Rights-of-Way

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our pipelines and facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our pipelines and facilities are located are held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessors. We, or our Predecessor, have leased or owned much of these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership to such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses.

Some of the leases, easements, rights-of-way, permits and licenses to be transferred to us at the closing of this offering require the consent of the grantor of such rights, which in certain instances is a governmental entity. We expect to obtain, prior to the closing of this offering, sufficient third-party consents, permits and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects as described in this prospectus. With respect to any material consents, permits or authorizations that have not been obtained prior to the closing of this offering, the closing will not occur unless a reasonable basis exists that permits us to conclude that such consents, permits or authorizations will be obtained within a reasonable period following the closing, or the failure to obtain such consents, permits or authorizations will have no material adverse effect on the operation of our business.

 

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Chesapeake, Chesapeake Midstream Ventures or their affiliates may initially continue to hold record title to portions of certain assets until we make the appropriate filings in the jurisdictions in which such assets are located and obtain any consents and approvals that are not obtained prior to transfer. Such consents and approvals would include those required by federal and state agencies or political subdivisions. In some cases, Chesapeake may, where required consents or approvals have not been obtained, temporarily hold record title to property as nominee for our benefit and in other cases may, on the basis of expense and difficulty associated with the conveyance of title, cause its affiliates to retain title, as nominee for our benefit, until a future date. We anticipate that there will be no material change in the tax treatment of our common units resulting from Chesapeake holding the title to any part of such assets subject to future conveyance or as our nominee.

Employees

The officers of our general partner will manage our operations and activities. As of September 30, 2009, our general partner and Chesapeake jointly employed approximately 220 people who will provide direct support to our operations. All of the employees required to conduct and support our operations are employed jointly by our general partner and Chesapeake pursuant to an employee secondment agreement between our general partner and Chesapeake Energy Corporation and certain of its affiliates and, with respect to our chief executive officer, pursuant to a shared services agreement between our general partner and Chesapeake Energy Corporation. None of these employees are covered by collective bargaining agreements, and Chesapeake considers its employee relations to be good.

Legal Proceedings

We are not a party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Please read “—Regulation of Operations” and “—Environmental Matters.”

 

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MANAGEMENT

Management of the Partnership

Board of Directors

Chesapeake Midstream GP, L.L.C., our general partner, will manage our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election in the future. Unitholders will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. However, our general partner owes a fiduciary duty to our unitholders. Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Our general partner, therefore, may cause us to incur indebtedness or other obligations that are nonrecourse to it and we expect that it will do so.

The directors of our general partner will oversee our operations. Chesapeake Midstream Ventures is the sole member of our general partner and will have the right to appoint our general partner’s entire board of directors, including our three independent directors. Upon the closing of this offering, we expect that our general partner will have seven directors, two of whom will be designated by Chesapeake, two of whom will be designated by GIP and three of whom will be independent as defined under the independence standards established by the NYSE and the Exchange Act. The NYSE does not require a listed publicly traded partnership, like us, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating/corporate governance committee.

In evaluating director candidates, Chesapeake and GIP will assess whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the board’s ability to manage and direct the affairs and business of the partnership, including, when applicable, to enhance the ability of committees of the board to fulfill their duties.

Committees

At least two independent members of the board of directors of our general partner will serve on a conflicts committee to review specific matters that the board believes may involve conflicts of interest (including certain transactions with Chesapeake, GIP and/or Chesapeake Midstream Ventures) and determines to submit to the conflicts committee for review.              and              will serve as the initial independent members of the conflicts committee. The conflicts committee will determine if the resolution of the conflict of interest is fair and reasonable to us. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Chesapeake, GIP and/or Chesapeake Midstream Ventures, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

In addition, our general partner will have an audit committee of at least three directors who meet the independence and experience standards established by the NYSE and the Exchange Act.             ,              and              will serve as the initial independent members of the audit committee.              will satisfy the definition of audit committee financial expert for purposes of the SEC’s rules. The audit committee will assist the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee will have the sole authority to, among other things, (i) retain and terminate our independent registered public accounting firm, (ii) approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and (iii) establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee will also be responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will be given unrestricted access to the audit committee and our management, as necessary.

 

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Executive Officers

The officers of our general partner will manage and conduct our operations. All of the executive officers of our general partner, other than Mr. Stice, the chief executive officer of our general partner, will devote all of their time to manage and conduct our operations. Mr. Stice will allocate his time between managing our business and affairs and the business and affairs of Chesapeake and, as such, may face a conflict regarding the allocation of his time between our business and the other business interests of Chesapeake. We expect that Mr. Stice will initially devote a substantial amount of his time to our business, although we expect the amount of time that he devotes may increase or decrease in the future as our business develops. The officers of our general partner and other Chesapeake employees will operate our business and provide us with general and administrative services pursuant to the omnibus agreement and the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement, each as described in “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Employee Secondment Agreement,” “—Omnibus Agreement” and “—Shared Services Agreement.”

Our general partner will not receive any management fee or other compensation for its management of our partnership under the omnibus agreement, the employee secondment agreement or otherwise. Under the omnibus agreement, Chesapeake will perform centralized corporate functions for us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake on a monthly basis for the time and materials actually spent in providing general and administrative support to our operations. Our reimbursement to Chesapeake of such general and administrative expenses in any given month will be subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process in such month. The $0.03 per Mcf cap will be subject to an annual upward adjustment on October 1st of each year equal to 50% of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented after the closing of the offering. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement.” In addition, under the employee secondment agreement, specified employees of Chesapeake will be seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner will, subject to specified exceptions and limitations, reimburse Chesapeake on a monthly basis for all costs and expenses it incurs relating to such seconded employees. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Employee Secondment Agreement.”

Directors and Executive Officers

The following table shows information regarding the current executive officers and directors of our general partner. Directors are appointed for a term of one year. Our directors hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers.

 

Name

  

Age

  

Position with Chesapeake Midstream GP, L.L.C.

J. Mike Stice

   50    Chief Executive Officer

Robert S. Purgason

   53    Chief Operating Officer

David C. Shiels

   44    Chief Financial Officer

Matthew C. Harris

   49    Director

Aubrey K. McClendon

   50    Director

Marcus C. Rowland

   57    Director

William A. Woodburn

   59    Director

 

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J. Mike Stice has served as Chief Executive Officer of our general partner since January 2010. Mr. Stice was appointed Senior Vice President—Natural Gas Projects of Chesapeake Energy Corporation and President and Chief Operating Officer of Chesapeake’s primary midstream subsidiaries in November 2008. Prior to joining Chesapeake, Mr. Stice spent 27 years with ConocoPhillips and its predecessor companies, where he most recently served as President of ConocoPhillips Qatar, responsible for the development, management and construction of natural gas liquefaction and regasification (LNG) projects. While at ConocoPhillips, he also served as Vice President of Global Gas LNG, as President of Gas and Power and as President of Energy Solutions in addition to other roles in ConocoPhillips’ midstream business units. Mr. Stice graduated from the University of Oklahoma in 1981 and from Stanford University in 1995.

Robert S. Purgason has served as Chief Operating Officer of our general partner since January 2010. Prior to joining our general partner, Mr. Purgason spent five years at Crosstex Energy Services, L.P. and was promoted to Executive Vice President—Chief Operating Officer in November 2006. Prior to Crosstex, Mr. Purgason spent 19 years with The Williams Companies in various senior business development and operational roles. Mr. Purgason began his career at Perry Gas Companies in Odessa, Texas working in all facets of the natural gas treating business. Mr. Purgason graduated from the University of Oklahoma in 1978.

David C. Shiels has served as Chief Financial Officer of our general partner since January 2010. For 13 years prior to joining our general partner, Mr. Shiels held multiple regional chief financial officer roles with subsidiaries of General Electric. Mr. Shiels most recently served as Chief Financial Officer of GE Security Americas. Prior to General Electric, Mr. Shiels spent 9 years with Conoco, Inc. in various finance and operational roles. Mr. Shiels graduated from Michigan State University in 1988.

Matthew C. Harris has served as a director of our general partner since January 2010. Mr. Harris is currently a partner of GIP leading GIP’s energy/waste industry investment team globally. He is a member of the board of GIP and of its Investment and Portfolio Valuation Committees. Prior to the formation of GIP in 2006, Mr. Harris was a Managing Director in the Investment Banking Department at Credit Suisse. Most recently, he was Co-Head of the Global Energy Group and Head of the EMEA Emerging Markets Group. Prior to 2003, Mr. Harris was a senior member of the Mergers and Acquisitions Group and served as Co-Head of Americas M&A. From 1984 to 1994, he was a senior member of the Mergers and Acquisitions Group of Kidder Peabody & Co. Incorporated. Mr. Harris is a director of the GIP portfolio companies Biffa and Ruby Pipeline Holding Company LLC. Mr. Harris graduated from the University of California at Los Angeles in 1984.

Aubrey K. McClendon has served as a director of our general partner since January 2010. Mr. McClendon has served as Chairman of the Board, Chief Executive Officer and a director of Chesapeake since co-founding Chesapeake in 1989. From 1982 to 1989, Mr. McClendon was an independent producer of oil and natural gas. Mr. McClendon graduated from Duke University in 1981.

Marcus C. Rowland has served as a director of our general partner since January 2010. Mr. Rowland was appointed Executive Vice President of Chesapeake in 1998 and has been its Chief Financial Officer since 1993. He served as Senior Vice President of Chesapeake from 1997 to 1998 and as Vice President—Finance from 1993 until 1997. From 1990 until he joined Chesapeake, Mr. Rowland was Chief Operating Officer of Anglo-Suisse, L.P. assigned to the White Nights Russian Enterprise, a joint venture of Anglo-Suisse, L.P. and Phibro Energy Corporation, a major foreign operation which was granted the right to engage in oil and gas operations in Russia. Prior to his association with White Nights Russian Enterprise, Mr. Rowland owned and managed his own natural gas and oil company and prior to that was Chief Financial Officer of a private exploration company in Oklahoma City from 1981 to 1985. Mr. Rowland is a Certified Public Accountant. Mr. Rowland graduated from Wichita State University in 1975.

William A. Woodburn has served as a director of our general partner since January 2010. Mr. Woodburn is currently a partner of GIP and oversees GIP’s operating team. Mr. Woodburn is a member of the board of GIP and of its Investment and Portfolio Valuation Committees and serves as chairman of its Portfolio Committee. Prior to the formation of GIP in 2006, Mr. Woodburn was the President and Chief Executive Officer of GE Infrastructure, which encompassed Water Technologies, Security and Sensing Growth Platforms and GE Fanuc

 

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Automation. Prior to his tenure at GE Infrastructure, Mr. Woodburn served as President and Chief Executive Officer of GE Specialty Materials. From 2000 to 2001, Mr. Woodburn served as Executive Vice President and member of the Office of Chief Executive Officer at GE Capital and served as a member the board of GE Capital from 2000 to 2001. Mr. Woodburn joined General Electric in 1984 and held leadership positions at GE Lighting (1984-1993) and GE Superabrasives (1994-2000). Prior to joining General Electric, Mr. Woodburn held process engineering and marketing positions at Union Carbide’s Linde Division for five years and was an engagement manager at McKinsey & Company for four years focusing on energy and transportation industries. Mr. Woodburn is a director of the GIP portfolio companies Biffa, Gatwick Airport Limited and Terra-Gen Power Holdings, LLC. Mr. Woodburn graduated from the U.S. Merchant Marine Academy in 1973 and from Northwestern University in 1975.

Executive Compensation

We and our general partner were formed in January 2010 and we expect to complete our initial public offering in 2010. Accordingly, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for our directors and officers for the fiscal year ended December 31, 2009, or for any prior periods. Because the executive officers of our general partner are employees of Chesapeake, compensation and participation in benefit plans will be determined and paid by Chesapeake, subject to the approval of our general partner’s board of directors for individuals whose aggregate annual compensation exceeds $300,000. The officers of our general partner, as well as the employees of Chesapeake who provide services to us, may also participate in employee benefit plans and arrangements sponsored by Chesapeake, including plans that may be established in the future.

Chesapeake Midstream Management, L.L.C., a subsidiary of Chesapeake, has adopted a management incentive compensation plan pursuant to which awards have been and may be granted to certain of our executive officers, as described below. Chesapeake has also entered into employment agreements with our executive officers, which are described below. We will reimburse Chesapeake for the obligations it incurs under these agreements pursuant to the employee secondment agreement and, in the case of Mr. Stice, the shared services agreement. We also expect that, in connection with the closing of this offering and in the future, the board of directors of our general partner will grant awards to our executive officers and other key employees and our outside directors pursuant to the long-term incentive plan described below; however, except as described under “Compensation of Directors” below, the board has not yet made any determination as to the number of awards, the type of awards or when the awards would be granted.

Compensation of Directors

Officers or employees of Chesapeake and GIP who also serve as directors of our general partner will not receive additional compensation for their service as a director of our general partner. Our general partner anticipates that our independent directors will receive compensation for attending meetings of the board of directors of our general partner. Such compensation will consist of an annual retainer of $60,000 for each board member, a fee of $2,500 for each board meeting attended in person and a fee of $1,000 for each telephonic board meeting attended. The independent directors will also receive an annual grant of the number of units having a grant date value of $50,000, 25% of which will be vested on the grant date and 75% of which will be restricted units that vest one-third on each of the first, second and third anniversary of the date of grant (with vesting to be accelerated upon death, disability or a change of control of our general partner). In addition, each director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees. Each director will be fully indemnified by us, pursuant to individual indemnification agreements and our partnership agreement, for actions associated with being a director to the fullest extent permitted under Delaware law.

Compensation Discussion and Analysis

Overview . We do not directly employ any of the persons responsible for managing our business. Chesapeake Midstream GP, L.L.C., our general partner, will manage our operations and activities, and its board of directors

 

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and officers will make decisions on our behalf. Chesapeake has decision-making authority with respect to the total compensation, subject to the approval of Chesapeake Midstream Ventures, L.L.C.’s board, of individuals whose aggregate annual compensation exceeds $300,000 and, subject to the terms of the shared services agreement concerning Mr. Stice and the employee secondment agreement, with respect to the portion of such compensation that will be reimbursed by us. Awards under the management incentive compensation plan to certain executive officers were made with the approval of the board of managers of the joint venture formed by Chesapeake and GIP, and future awards will be made by the board of managers of Chesapeake Midstream Ventures. Awards under our long-term incentive plan to our general partner’s executive officers, key employees and independent directors will be made by our general partner’s board of directors.

Mr. Stice is an officer of both our general partner and Chesapeake. The compensation of Chesapeake’s employees who perform services on our behalf (other than the long-term incentive plan benefits described below), including our executive officers, will be approved by Chesapeake’s management. Awards under our long-term incentive plan will be recommended by Chesapeake’s management and approved by the board of directors of our general partner. Our reimbursement for the compensation of executive officers is governed by, and subject to the limitations contained in the omnibus agreement, the employee secondment agreement and the shared services agreement. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Shared Services Agreement.”

As previously discussed, our general partner has not accrued any obligations with respect to management incentive or retirement benefits for its directors and officers for the fiscal year ended December 31, 2009, or for any prior periods. Accordingly, we are not presenting any compensation for historical periods. Following the consummation of this offering, we expect that the most highly compensated executive officers of our general partner for 2010 will be Mr. Stice (the principal executive officer), Robert S. Purgason (the principal operating officer), and David C. Shiels (the principal financial and accounting officer) (collectively, the “named executive officers”). With the exception of Mr. Stice, our general partner’s chief executive officer, we expect that the named executive officers will have all of their total compensation allocated to us as compensation expense in 2010. We expect that Mr. Stice will have approximately 50% of his total compensation allocated to us as compensation expense in 2010. Compensation paid or awarded by us in 2010 with respect to the named executive officers will reflect only the portion of compensation expense that is payable by us pursuant to the terms of the shared services agreement concerning Mr. Stice and the employee secondment agreement.

We expect that the future compensation of our named executive officers will be structured in a manner similar to how Chesapeake compensates its executive officers. The following discussion relating to compensation paid by Chesapeake is based on information provided to us by Chesapeake and does not purport to be a complete discussion and analysis of Chesapeake’s executive compensation philosophy and practices. The elements of compensation discussed below, and Chesapeake’s decisions with respect to future changes to the levels of such compensation, are subject to the approval of our general partner’s board of directors.

Chesapeake’s Executive Compensation Program Objectives, Design and Process.

Chesapeake’s compensation program is designed to take into consideration and reward the following performance factors:

 

   

Individual performance—for example, the employee’s contributions to the development and execution of Chesapeake’s business plan and strategies, performance of the executive’s department or functional unit, level of responsibility and longevity;

 

   

Chesapeake’s performance—including operational performance, with respect to production, reserves, operating costs, drilling results, risk management activities and asset acquisitions and financial performance, with respect to cash flow, net income, cost of capital, general and administrative costs and common stock price performance; and

 

   

Intangibles—for example, leadership ability, demonstrated commitment to the organization, motivational skills, attitude and work ethic.

 

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Chesapeake believes objective performance criteria cannot differentiate the executive officers’ individual and collective contributions from the impact of external factors beyond Chesapeake’s control (for example, extreme economic crises and the volatility in natural gas and oil prices). Moreover, Chesapeake believes that reliance on objective metrics (for example, natural gas production) may encourage the executive officers to take operational risks that could be contrary to Chesapeake’s long-term interests (for example, increasing natural gas production during a period of uncertain or depressed pricing). Therefore, Chesapeake’s compensation committee continues to highly value the subjectivity it retains in its review of executive compensation.

Elements and Mix of Compensation.

Chesapeake provides short-term compensation in the form of base salaries and cash bonuses and long-term compensation in the form of Chesapeake restricted stock awards and 401(k) matching. However, under the terms of the employee secondment agreement, David C. Shiels and Robert S. Purgason are not eligible to receive Chesapeake restricted stock awards, and, instead, their interests in the management incentive compensation plan, described below, provide them with our equity-related incentive compensation. Additionally, Chesapeake’s more highly-compensated employees, including Mr. Stice, are eligible to defer certain compensation through a nonqualified deferred compensation program and to receive certain perquisites. Messrs. Purgason and Shiels are not eligible to participate in Chesapeake’s non-qualified deferred compensation program.

Chesapeake believes that as an employee’s business responsibilities increase, the proportion of his or her variable, long-term compensation as a percentage of total compensation should increase. Therefore, depending upon an executive officer’s level of responsibility, his or her annual base salary is typically less than 20% of the executive’s total cash and equity compensation and an executive’s total cash compensation is generally less than 40% of the executive’s total cash and equity compensation. Chesapeake does not utilize pre-determined guidelines for allocating between cash and equity and short-term and long-term compensation.

Base Salary . The base salary levels of Chesapeake’s executive officers are intended to reflect each officer’s level of responsibility, leadership ability, tenure and the contribution of the officer’s department or functional unit to the success and profitability of the Company. Although Chesapeake reviews the salary levels of executive officers of peer companies to determine whether Chesapeake’s executive officers’ salaries are reasonable in comparison, Chesapeake does not specifically target a percentile or range within peer group salary levels for our executive officers’ salaries.

Cash Bonuses . Cash bonuses are awarded to the executive officers based on a subjective evaluation of the performance of Chesapeake and the individual during the six-month review period. Chesapeake’s financial and operating performance measurements are based, collectively, on reserves, production, net income, cash flow, drilling results, finding and operating costs, general and administrative costs, asset acquisitions and divestitures, risk management activities and common stock price performance. Individual performance factors include leadership, commitment, attitude, motivational effect, level of responsibility, prior experience and extraordinary contributions to Chesapeake. Additionally, individual performance by an executive officer in a review period that is expected to provide substantial benefit to Chesapeake in future periods is also considered in semi-annual cash bonus decisions. Examples might include the acquisition of key acreage to be used for natural gas and oil development in future periods, the consummation of significant joint venture or joint participation arrangements, the consummation of credit or financing arrangements that reduce Chesapeake’s potential needs for liquidity in future unstable economic periods or the execution of hedging contracts that lock in attractive natural gas and oil prices for future production months.

Cash bonuses are discretionary and not awarded pursuant to a formal plan or an agreement with any executive officer. Additionally, cash bonuses are not awarded based on objective company or individual performance criteria or targets. No single company or individual performance measurement is given more weight than another and the Compensation Committee of Chesapeake is not prohibited from awarding cash bonuses to an executive even if the executive’s performance in any given area is poor during the relevant review period.

 

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Restricted Stock . Consistent with Chesapeake’s compensation objectives, Chesapeake believes stock-based compensation provides strong incentives for long-term performance that increases shareholder value while retaining executive officers. Specifically, in conjunction with the Compensation Committee’s semi-annual review of cash compensation, on the first trading day of each January and July, Chesapeake awards restricted stock that vests over a period of four years to employees, including executive officers. Chesapeake prefers to award restricted stock, rather than stock options, for the following reasons:

 

   

Chesapeake’s annual stock usage rate or “burn rate” is smaller with restricted stock than with stock options, without a reduction in compensation value transferred to the executives;

 

   

A lower annual stock usage rate reduces the dilutive effect of stock compensation to shareholders;

 

   

The income statement impact of restricted stock is more predictable, and less volatile, than that of stock options; and

 

   

Structurally, Chesapeake believes restricted stock better facilitates long-term employee stock ownership than stock options.

Restricted stock is awarded to the executive officers based on a comprehensive but subjective evaluation of the performance of Chesapeake and the individual during the six-month review period, rather than based on objective company or individual performance criteria or targets. No single company or individual performance measurement is given more weight than another. Because the semi-annual award of restricted stock to our employees is primarily intended to provide incentives for future performance and not rewards for prior performance, when granting restricted stock to executive officers, the Compensation Committee does not consider current holdings of Chesapeake securities, the amount and terms of stock options or restricted stock previously granted to the executive officer or gains realized by the executive officer from prior awards of restricted stock or stock options, although such prior awards do continue to provide long-term value and incentive to the executive officers beyond the initial award period.

Under the shared services agreement concerning Mr. Stice, we will reimburse Chesapeake with respect to restricted stock awards called for under the terms of Mr. Stice’s employment agreement but not any discretionary restricted stock awards. As mentioned above, David C. Shiels and Robert S. Purgason are not eligible to receive Chesapeake restricted stock awards based on a restriction in the employee secondment agreement. Because Messrs. Shiels and Purgason were first employed by Chesapeake in December 2009 and January 2010, respectively, in terms of equity-related compensation, we provided them only with awards under the management incentive compensation plan to most closely align their interests with our success (in terms of distributions and unit value), as described below.

Other Compensation Arrangements . Chesapeake also provides compensation in the form of personal benefits and perquisites to our executive officers. Most of the benefits that Chesapeake provides to executive officers are the same benefits that are provided to all employees or large groups of senior-level employees, including health and welfare insurance benefits, 401(k) matching contributions, nonqualified deferred compensation arrangements and financial planning services. Chesapeake does not have a pension plan or any other retirement plan other than the 401(k) and nonqualified deferred compensation plan.

The perquisites that Chesapeake provides exclusively to executive officers include reimbursement of monthly country club dues and personal use of fractionally-owned company aircraft. Feedback from Chesapeake’s executive officers indicates that access to fractionally-owned company aircraft for personal use greatly enhances productivity and work-life balance which Chesapeake believes may impact their willingness to work to or beyond normal retirement age. Chesapeake’s Compensation Committee regularly reviews the terms under which these perquisites are provided and their value in relation to the executive’s total compensation package; however, as these benefits and perquisites represent generally less than 10% of the executive officers’ total compensation, they do not materially influence Chesapeake’s Compensation Committee’s decisions in setting such officers’ total compensation. Further, Chesapeake includes the above benefits and perquisites as

 

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taxable income to the executive on Form W-2 after each fiscal year, in accordance with Internal Revenue Service (IRS) guidelines. Messrs. Purgason and Shiels do not receive dues reimbursement or any aircraft perquisites.

The Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, our qualified 401(k) profit sharing plan, is open to all employees of Chesapeake and its subsidiaries except employees covered by collective bargaining agreements (approximately 135 employees). Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) plan accounts, subject to plan limits and those set by the IRS. Chesapeake matches employee contributions dollar for dollar with shares of our common stock purchased in the open market for up to 15% of an employee’s annual base salary and bonus compensation.

Employment Agreements

Messrs. Stice, Purgason and Shiels have entered into employment agreements that govern the terms and conditions of their employment, including their duties and responsibilities, compensation and benefits, and applicable severance terms. Mr. Stice is employed by Chesapeake Energy Corporation and his services are shared with us, and we share in the expenses of his compensation under a shared services agreement. Messrs. Purgason and Shiels are employed by Chesapeake Midstream Management L.L.C. but their services are wholly dedicated to us under an employee secondment agreement, which also governs our obligation to reimburse Chesapeake Midstream Management L.L.C. for the cost of their compensation and benefits. The shared services agreement and employee secondment agreement are further described in “Certain Relationships and Related Party Transactions.”

Agreement with J. Mike Stice, President and Chief Executive Officer

Mr. Stice’s employment agreement was originally entered into effective as of October 5, 2008 and was amended and restated effective as of November 10, 2008, and was subsequently amended on September 30, 2009. His employment agreement has a three-year term. Pursuant to the shared services agreement, our general partner is generally required, subject to certain exceptions, to reimburse Chesapeake Energy Corporation for 50% of the costs and expenses of the amounts provided to Mr. Stice in his employment agreement; however, the ultimate reimbursement obligation is determined based on the amount of time Mr. Stice actually spends working for us.

The agreement provides Mr. Stice will serve as the Chief Executive Officer of our general partner with a current annual base salary of $500,000, which will increase to $600,000 no later than January 1, 2011. Mr. Stice is entitled to guaranteed annual bonuses for calendar years 2010 and 2011, in the amount of $350,000 and $425,000, respectively, payable by January 31 of the following year, provided Mr. Stice remains employed on the bonus payment dates. Additional, discretionary bonuses may be made. Mr. Stice is also entitled to participate in the employee benefit plans and arrangements, such as retirement and health plans and vacation programs, that are customarily provided to other employees, to the extent he is eligible under the terms and conditions of such arrangements. In addition, Mr. Stice receives reimbursement for up to $750 in monthly country club dues and the reasonable cost of any approved business entertainment. Mr. Stice also is entitled to receive the following grants of Chesapeake Energy Corporation restricted stock, provided he remains employed on the applicable grant date: (a) at least $1,250,000 worth of restricted stock, granted no later than January 31, 2011 (the “2011 Grant”), and (b) at least $1,750,000 worth of restricted stock, granted no later than January 31, 2012.

Mr. Stice’s employment agreement provides for certain change in control and termination benefits in the event of a change in control or a termination of Mr. Stice’s employment under certain circumstances, as applicable. If a change in control (as defined in the employment agreement) occurs during the term of the agreement, Mr. Stice will receive a lump sum payment equal to 200% of the sum of Mr. Stice’s current annual base salary and the actual bonuses paid to Mr. Stice during the twelve month period preceding the change in control, subject to interest if not paid within 30 days of the change in control.

Upon written notice, Mr. Stice’s employment may be terminated by either party to his agreement for any reason. Generally, upon any termination, Mr. Stice will be entitled to receive only accrued but unpaid

 

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compensation, such as vacation amounts, and any amounts due to him pursuant to the terms of an employee benefit plan. In the event Mr. Stice’s employment is terminated without cause (as defined in the agreement to include certain constructive termination events), he will also be entitled to the following: (i) a lump sum payment equal to one year’s worth of base salary, (ii) all restricted stock granted under the agreement will vest in full upon the termination, and (iii) if the termination occurs before January 31, 2011, and Mr. Stice has not yet received the 2011 Grant, a payment, in either cash or Chesapeake stock, equal to $1,250,000.

In the event of Mr. Stice’s retirement following at least five years of service and the attainment of at least age 55, Mr. Stice will receive accelerated vesting, in whole or in part, of (i) his supplemental matching contributions under the Chesapeake Energy Corporation 401(k) Make-Up Plan, and (ii) all unvested equity compensation (other than any equity compensation issued under the 2006 Long-Term Stock Incentive Program). If Mr. Stice dies, his beneficiary or estate will be entitled to continue receiving his base salary for a period of one year following his date of death and all restricted Chesapeake stock granted under the agreement will vest in full, subject to the execution (and nonrevocation) of the severance and release agreement described below.

If Mr. Stice is terminated due to a disability (as defined in the employment agreement), he will continue to receive his base salary and other compensation for a period of 180 days following the termination date, reduced by any benefits payable under any employer-sponsored disability plan. In addition, if the termination occurs before January 31, 2011, and Mr. Stice has not yet received the 2011 Grant, he will receive a payment, in either cash or Chesapeake stock, equal to $1,250,000.

All severance payments due upon Mr. Stice’s termination without cause or due to his disability will be made within 60 days of the termination date, unless Mr. Stice constitutes a “specified employee” within the meaning of section 409A of the Internal Revenue Code, in which case payments subject to section 409A will be delayed for six months following the termination date. All severance payments and benefits are contingent on Mr. Stice (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 45 days of the termination, and complying with the restrictive covenants described below.

Mr. Stice’s agreement contains certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Mr. Stice has agreed not to disclose any confidential information during the term of his employment and for three years following his termination. In addition, Mr. Stice has agreed to a noncompete covenant for six months following his termination and not to solicit customers or employees for a period of one year following his termination.

Agreements with Robert S. Purgason, Chief Operating Officer, and David C. Shiels, Chief Financial Officer

Messrs. Purgason and Shiels employment agreements are effective December 1, 2009 and January 4, 2010, respectively. The employment agreements each have a five-year term. Mr. Purgason will serve as our general partner’s Chief Operating Officer, and Mr. Shiels will serve as our general partner’s Chief Financial Officer.

The agreements provide Messrs. Purgason and Shiels with an annual base salary of $350,000 and $300,000, respectively, which will increase to $375,000 and $325,000, respectively, effective January 31, 2011, and to $400,000 and $350,000, respectively, effective January 31, 2012. Messrs. Purgason and Shiels are each entitled to a signing bonus of $100,000 and $125,000, respectively, payable three months following the effective dates of their respective agreements. If either executive voluntarily terminates during his first year of employment, he will be required to repay a pro rata share of the signing bonus. Additionally, the agreements specify target annual bonuses for Messrs. Purgason and Shiels in the following amounts, payable in cash: (i) $300,000 and $100,000, respectively, payable not later than January 31, 2011, (ii) $325,000 and $125,000, respectively, payable not later than January 31, 2012, and (iii) $350,000 and $150,000, respectively, payable not later than January 31, 2013, provided Messrs. Purgason and Shiels remain employed on the bonus dates. Payment of any bonus compensation

 

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is not guaranteed and remains within the discretion of Chesapeake Midstream Management L.L.C., with approval of our general partner’s board. Additionally, discretionary bonuses above the target bonus amounts may be made, in cash or stock, based on each executive’s annual performance review.

Messrs. Purgason and Shiels are also entitled to participate in the employee benefit plans and arrangements, such as retirement and health plans and vacation programs, that are customarily provided to other employees, to the extent eligible under the terms and conditions of such arrangements. They are also each entitled to receive (i) a relocation allowance of $50,000, payable within 30 days of relocation, provided relocation occurs within six months of the effective date of the agreement (18 months in the case of Mr. Shiels) and subject to a pro rata repayment obligation in the event of a voluntary termination during the first twelve months of the employment term (first 18 months of the employment term, in the case of Mr. Shiels), and reasonable temporary housing costs for up to 90 days, and (ii) reimbursement of the actual cost of health insurance premiums incurred for COBRA coverage until Messrs. Purgason and Shiels qualify for health coverage by reason of their employment. Until the time Mr. Shiels relocates to the Oklahoma City area or, if earlier, the 18 month anniversary of the effective date of his agreement, Mr. Shiels will also be entitled to a monthly commuting allowance of $1,500.

The agreements further provide that Messrs. Purgason and Shiels will each be awarded a percentage interest in a management incentive cash bonus pool, which will be based on our long-term performance following the initial public offering. These awards will be granted pursuant to Chesapeake Midstream Management, L.L.C.’s management incentive compensation plan, described below. Messrs. Purgason and Shiels may also be granted equity-based awards under our long-term incentive plan, described below, that will be subject to certain service and/or performance-based vesting requirements.

The employment agreements also provide for certain termination benefits in the event of a termination of Mr. Purgason or Mr. Shiels under certain specified circumstances. Upon written notice, Mr. Purgason’s or Mr. Shiels’s employment may be terminated by either party to the agreement for any reason. Generally, upon any termination, Messrs. Purgason and Shiels will be entitled to receive only accrued but unpaid compensation, such as base salary and vacation amounts, and any amounts due to them pursuant to the terms of an employee benefit plan.

In the event Mr. Purgason’s or Mr. Shiels’s employment is terminated without cause (as defined in the employment agreement to include certain constructive termination events), he will also be entitled to a lump sum payment equal to one year’s worth of base salary (26 weeks’ worth of base salary, in the case of Mr. Shiels). If the termination without cause occurs within two years following the occurrence of a change in control (as defined in the employment agreement), Messrs. Purgason and Shiels are also entitled to receive, in addition to the base salary amounts described in the preceding sentence, an amount equal to the actual bonuses paid to them during the 12 calendar months preceding the change in control.

If either Mr. Purgason or Mr. Shiels is terminated due to a disability (as defined in the employment agreement), he will be entitled to a lump sum payment equal to 26 weeks’ worth of base salary, reduced by any benefits payable under any employer-sponsored disability plan. If either Mr. Purgason or Mr. Shiels dies, his beneficiary or estate will be entitled to receive a lump sum payment equal to 52 weeks’ worth of his base salary.

All payments due upon the termination of Messrs. Purgason and Shiels will be made within 30 days of the termination date (90 days, in the case of death), unless the executive constitutes a “specified employee” within the meaning of section 409A of the Internal Revenue Code, in which case payments subject to section 409A will be delayed until the earlier of the executive’s death or six months following the termination date. Such payments are contingent on the Executive (or, in the event of his death, his beneficiary or the administrator of his estate) executing (and not revoking) a severance and release agreement within 30 days of the termination (90 days, in the case of death), and complying with the restrictive covenants described below.

The employment agreements with Messrs. Purgason and Shiels contain certain confidentiality, noncompete, and nonsolicitation covenants. Specifically, Messrs. Purgason and Shiels have agreed not to disclose any

 

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confidential information at any time either during or following the term of their employment. In addition, Messrs. Purgason and Shiels have agreed to a noncompete covenant for one year (26 weeks, in the case of Mr. Shiels) following termination and not to solicit customers or employees for a period of one year following termination. Termination of either Mr. Purgason’s or Mr. Shiels’s employment due to the violation of one of these covenants would constitute a termination for cause.

No amendments to the employment agreement with Messrs. Purgason and Shiels that would increase the compensation expenses reimbursable under the employee secondment agreement or adversely affect the protections afforded to us under the agreement may be made without the consent of the special committee of the board of managers of Chesapeake Midstream Ventures.

Management Incentive Compensation Plan

Chesapeake Midstream Management, L.L.C. has adopted the Chesapeake Midstream Management Incentive Compensation Plan, which we refer to as the “MICP,” which provides incentive compensation awards comprised of two components to key members of management who have been designated as participants by the board of managers of Chesapeake Midstream Ventures (the “Ventures Board”). The first component of the award is an annual bonus based on “excess” cash distributions made by us each fiscal year above a target amount each year during a five-year period (the “Excess Return Component”). The excess amount determined to be payable to a participant with respect to a specified fiscal year (if any) is paid prorata that year and in each of the years then remaining in the five-year period, provided the participant continues to be employed by us or an affiliate. The second component is based on an increase in value of our common units at the end of the five-year period and is paid at the end of the five-year period (the “Equity Uplift Component”). Unless waived by the Ventures Board, in its discretion, if a participant’s employment terminates for any reason prior to a payment date, other than due to his or her death, disability, involuntary termination by the employer other than for “cause” (as defined in the MICP), or by the participant for a “good reason” (as defined in the MICP) (such events collectively being a “Qualified Termination”), the participant’s award will be automatically forfeited on his or her termination of employment. If, however, a participant’s termination of employment is a Qualified Termination, the participant will be paid (i) on his or her termination the remaining amount of any unpaid annual installments attributable to the participant’s Excess Return Component for the fiscal years that have been completed as of the participant’s termination date, and (ii) at the end of the five-year period, a prorata portion of the participant’s Equity Uplift Component (if any) during such five-year period. Awards will be paid in cash, unless the Ventures Board elects, in its discretion, to pay all or part of the second component of the award in our common units.

Upon a change of control (as defined in the MICP), a participant who is an employee immediately prior to the change of control will be paid (i) with respect to the Excess Return Component, the remaining amount of unpaid installments attributable to fiscal years then completed and (ii) with respect to the Equity Uplift Component, an amount based on the increase in the value of our common units over the beginning value of our common units. Participants who have incurred a Qualified Termination prior to the change of control will receive, with respect to the Equity Uplift Component, a prorata portion of the amount that otherwise would have been payable to them had their employment continued until the change of control. The MICP will terminate on a change of control.

The MICP will be administered by the Ventures Board, which also has the authority to amend and terminate the MICP at any time, subject to certain limitations with respect to Excess Return payments that are based on fiscal years that have already lapsed at such time and Equity Uplift payments based on their accrued value at such time.

Long-Term Incentive Plan

General

Our general partner has adopted the Chesapeake Midstream Long-Term Incentive Plan, which we refer to as the LTIP, for employees, consultants and directors of our general partner and its affiliates, including Chesapeake, who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is

 

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qualified in its entirety by reference to the LTIP. The LTIP provides for the grant of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. Subject to adjustment for certain events, an aggregate of                  common units may be delivered pursuant to awards under the LTIP. Units that are cancelled or forfeited are available for delivery pursuant to other awards. Units that are withheld to satisfy our general partner’s tax withholding obligations or payment of an award’s exercise price are not available for future awards. The LTIP will be administered by our general partner’s board of directors. The LTIP has been designed to promote the interests of the partnership and its unitholders by strengthening its ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees.

Unit Awards

Our general partner’s board of directors may grant unit awards to eligible individuals under the LTIP. A unit award is an award of common units that are fully vested upon grant and are not subject to forfeiture. Unit awards may be paid in addition to, or in lieu of, cash that would otherwise be payable to a participant with respect to a bonus or an incentive compensation award. The unit award may be wholly discretionary in amount or it may be paid with respect to a bonus or an incentive compensation award the amount of which is determined based on the achievement of performance criteria or other factors. Our general partner’s board of directors has approved unit award grants to each of Messrs.             ,              and              in connection with their election to the board. The units will be granted upon the closing of this offering and will have an aggregate value to each director of $12,500. The actual number of units awarded under this grant to each director will be determined by dividing $12,500 by the initial public offering price per unit.

Restricted Units and Phantom Units

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, in the discretion of our general partner’s board of directors, cash equal to the fair market value of a common unit. Our general partner’s board of directors may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the board may determine are appropriate, including the period over which restricted or phantom units will vest. The board may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement. In addition, the restricted and phantom units will vest automatically

Distributions made by us with respect to awards of phantom units may, in the board’s discretion, be subject to the same vesting requirements as the restricted units. The board, in its discretion, may also grant tandem distribution equivalent rights with respect to phantom units. Distribution equivalent rights are rights to receive an amount equal to all or a portion of the cash distributions made on units during the period a phantom unit remains “outstanding.” We intend for the restricted and phantom units granted under the LTIP to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, participants will not pay any consideration for the common units they receive with respect to these types of awards, and neither we nor our general partner will receive remuneration for the units delivered with respect to these awards.

Our general partner’s board of directors has approved restricted unit grants to each of Messrs.                     ,                  and                      in connection with their election to the board. The restricted units will be granted upon the closing of this offering and will have an aggregate value to each director of $37,500. The actual number of restricted units awarded under this grant will be determined by dividing $37,500 by the initial public offering price per unit. The restricted units will vest one third on each of the first, second and third anniversary of the grant date (with vesting to be accelerated upon death, disability or change of control of our general partner).

 

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Unit Options and Unit Appreciation Rights

The LTIP also permits the grant of options and unit appreciation rights covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units as determined by the board. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the board may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price greater than or equal to the fair market value of a common unit on the date of grant.

Other Unit-Based Awards

The LTIP also permits the grant of other unit-based awards, which are awards that, in whole or in part, are valued or based on or related to the value of a unit. The vesting of an other unit-based award may be based on a participant’s length of service, the achievement of performance criteria or other measures. On vesting, an other unit-based award may be paid in cash and/or in units (including restricted units), as the board of directors of our general partner may determine.

Source of Common Units; Cost

Common units to be delivered with respect to awards may be newly-issued units, common units acquired by our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us or any other person or any combination of the foregoing. Our general partner will be entitled to reimbursement by us for the cost incurred in acquiring such common units. With respect to unit options and unit appreciation rights, our general partner will be entitled to reimbursement from us for the difference between the cost it incurs in acquiring these common units and the proceeds it receives from an optionee at the time of exercise of an option. Thus, we will bear the cost of the unit options. If we issue new common units with respect to these awards, the total number of common units outstanding will increase, and our general partner will remit the proceeds it receives from a participant, if any, upon exercise of an award to us. With respect to any awards settled in cash, our general partner will be entitled to reimbursement by us for the amount of the cash settlement.

Amendment or Termination of Long-Term Incentive Plan

Our general partner’s board of directors, in its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP will automatically terminate on the earlier of the 10th anniversary of the date it was initially adopted by our general partner or when common units are no longer available for delivery pursuant to awards under the LTIP. Our general partner’s board of directors will also have the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP; provided, however, that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant, and/or result in taxation to the participant under Section 409A of the Code unless otherwise determined by the general partner’s board of directors.

 

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth the beneficial ownership of our units that, upon the consummation of this offering and the related transactions, will be owned by:

 

   

each person or group of persons known by us to be a beneficial owner of more than 5% of the then outstanding units;

 

   

each director of and nominee to the board of directors of our general partner;

 

   

each named executive officer of our general partner; and

 

   

all directors and executive officers of our general partner as a group.

 

Name and address of beneficial owner (1)

  Common units
to be
beneficially
owned (2)
  Percentage of
common units
to be
beneficially
owned (3)
    Subordinated
units to be
beneficially
owned
  Percentage of
subordinated
units to be
beneficially
owned (3)
    Percentage of
total
common and
subordinated
units to be
beneficially
owned (3)
 

Chesapeake Energy Corporation (4)

        %        50       

GIP (5)

             50       

J. Mike Stice

        %      —     —            

Robert S. Purgason

        %      —     —            

David C. Shiels

        %      —     —            

Matthew C. Harris (5)

        %      —     —            

Aubrey K. McClendon (4)

        %      —     —            

Marcus C. Rowland (4)

        %      —     —            

William A. Woodburn (5)

        %      —     —            

All directors and executive officers as a group (seven persons)

        %      —     —            

 

* Less than 1.0%
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118.
(2) Does not include common units that may be purchased in the directed unit program. Please see “Underwriting.”
(3) Based on                  common units and                  subordinated units outstanding.
(4) Chesapeake Energy Corporation is the ultimate parent company of Chesapeake Midstream Holdings, L.L.C., the owner of 50% of the membership interests of Chesapeake Midstream Ventures and the owner of common units and subordinated units. Chesapeake Energy Corporation may, therefore, be deemed to beneficially own the interests held directly or indirectly by Chesapeake Midstream Holdings, L.L.C.
(5)

Global Infrastructure Investors, Limited (“Global Infrastructure Investors”) and Global Infrastructure Management, LLC (“Global Infrastructure Management”), each located at 12 East 49 th Street, 38 th Floor, New York, New York 10017, may be deemed to beneficially own the interests in us held by GIP-A Holding (CHK), L.P. (“GIP-A”), GIP-B Holding (CHK), L.P. (“GIP-B”) and GIP-C Holding (CHK), L.P. (“GIP-C”). Global Infrastructure Investors is the sole general partner of Global Infrastructure GP, L.P., which is the sole general partner of the limited partnerships (the “GIP Partnerships”) that directly or indirectly own the general partners of each of GIP-A, GIP-B and GIP-C. Global Infrastructure Management manages the GIP Partnerships. GIP-A, GIP-B and GIP-C hold the following interests in us:

 

   

GIP-A owns              common units,              subordinated units and a 17.5817% membership interest in Chesapeake Midstream Ventures;

 

   

GIP-B owns              common units,              subordinated units and a 6.8197% membership interest in Chesapeake Midstream Ventures; and

 

   

GIP-C owns              common units,              subordinated units and a 25.5986% membership interest in Chesapeake Midstream Ventures.

 

   Matthew C. Harris and William A. Woodburn, two of the directors of our general partner, as members of Global Infrastructure Management’s internal committees, are entitled to vote on decisions to vote, or to direct to vote, and to dispose, or to direct the disposition of, the common units and subordinated units held by GIP-A, GIP-B and GIP-C but cannot individually or together control the outcome of such decisions. Global Infrastructure Investors, Matthew C. Harris and William A. Woodburn disclaim beneficial ownership of the common units and subordinated units held by GIP-A, GIP-B and GIP-C in excess of their respective pecuniary interest in such units. Global Infrastructure Investors and Global Infrastructure Management disclaim beneficial ownership of the common and subordinated units held by GIP-A, GIP-B and GIP-C.

 

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The following table sets forth, as of January 31, 2010, the number of shares of common stock of Chesapeake Energy Corporation owned by each of the executive officers, directors and nominees to the board of directors of our general partner and all directors and executive officers of our general partner as a group.

 

Name and address of beneficial owner (1)

   Shares of
common
stock owned
directly or
indirectly
   Shares
underlying
options
exercisable
within 60
days
   Total
shares of
common
stock
beneficially
owned
   Percentage
of total
shares of
common
stock
beneficially
owned (2)

J. Mike Stice

   10,264    —      10,264    *

Robert S. Purgason

   —      —      —      *

David C. Shiels

   —      —      —      *

Matthew C. Harris

   —      —      —      *

Aubrey K. McClendon

   894,748    —      894,748    *

Marcus C. Rowland

   96,394    —      96,394    *

William A. Woodburn

   —      —      —      *

All directors and executive officers as a group (seven persons)

   1,001,406    —      1,001,406    *

 

* Less than 1.0%
(1) Unless otherwise indicated, the address for all beneficial owners in this table is 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118.
(2) As of January 31, 2010, there were 651,871,290 shares of Chesapeake Energy Corporation common stock issued and outstanding.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, Chesapeake will own an aggregate of              common units and              subordinated units, representing an aggregate     % limited partner interest in us, and GIP will own an aggregate of              common units and subordinated units, representing an aggregate     % limited partner interest in us. In addition, Chesapeake and GIP, through their joint ownership of Chesapeake Midstream Ventures, will each indirectly own 50% of our general partner, which will own              general partner units representing a 2.0% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our formation, ongoing operation and any liquidation of Chesapeake Midstream Partners, L.P. These distributions and payments were determined by and among affiliated entities.

Formation Stage

 

The aggregate consideration received by Chesapeake and GIP for the contribution of the assets and liabilities to us

 

                     common units;

 

   

                     subordinated units;

 

   

                     general partner units; and

 

   

our incentive distribution rights.

Operational Stage

 

Distributions of available cash to our general partner and its affiliates

We will generally make cash distributions 98.0% to our unitholders pro rata, including Chesapeake and GIP as the holders of an aggregate                      common units and                      subordinated units, and 2.0% to our general partner, assuming it makes any capital contributions necessary to maintain its 2.0% interest in us. In addition, if distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner will be entitled to increasing percentages of the distributions, up to 50.0% of the distributions above the highest target distribution level.

Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of approximately $             million on its general partner units and Chesapeake and GIP would receive an aggregate annual distribution of approximately $             million on their common and subordinated units.

If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and general partner units. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels.”

 

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Payments to our general partner and its affiliates

Our general partner does not receive a management fee or other compensation for the management of our partnership. However, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf. Our general partner determines the amount of these expenses. In addition, we will reimburse Chesapeake for the provision of various general and administrative services for our benefit pursuant to the omnibus agreement, the costs and expenses of employees seconded to us pursuant to the employee secondment agreement, and certain costs and expenses incurred in connection with the services of Mr. Stice as the chief executive officer of our general partner pursuant to the shared services agreement. Please read “—Agreements with Affiliates—Omnibus Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement” below.

 

Withdrawal or removal of our general partner

If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests. Please read “The Partnership Agreement—Withdrawal or Removal of Our General Partner.”

Liquidation Stage

 

Liquidation

Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Agreements with Affiliates

We have or will enter into the various documents and agreements with Chesapeake Energy Corporation and certain of its affiliates, as described in more detail below. Substantially all of the commercial terms of these agreements were negotiated between Chesapeake and GIP in connection with their formation of the midstream joint venture Chesapeake MLP Operating, L.L.C. In connection with this offering, the commercial terms of these agreements are being incorporated into amended agreements that are generally intended to provide us with substantially similar benefits and obligations of the private midstream joint venture.

Omnibus Agreement

Upon the closing of this offering, our general partner will enter into an omnibus agreement with Chesapeake Energy Corporation and certain of its affiliates that will address the following matters:

 

   

Chesapeake’s obligation to provide us with certain rights relating to certain future midstream business opportunities;

 

   

our obligation to reimburse Chesapeake for certain expenses incurred or payments made on our behalf in conjunction with Chesapeake’s provision of general and administrative services and certain additional services to us;

 

   

our obligation to reimburse Chesapeake for insurance coverage expenses it incurs or payments it makes with respect to our business and operations and with respect to director and officer liability coverage; and

 

   

our right to indemnification for certain liabilities and our obligation to indemnify Chesapeake for certain liabilities.

 

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Business Opportunities . Pursuant to the omnibus agreement, Chesapeake will provide us with the opportunity to make offers with respect to three specified categories of transactions as described in more detail below: (i) proximate area opportunities, (ii) terminating third-party contract opportunities and (iii) monetization transaction opportunities. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with the applicable affiliate of Chesapeake Energy Corporation and our ability to obtain financing on acceptable terms. Although we will have certain rights with respect to the potential business opportunities described below, we are not under any contractual obligation to pursue any such transactions and Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities.

Proximate Area Opportunities . Chesapeake will be required to offer us the opportunity to make a first offer with respect to all potential investments in, opportunities to develop, or acquisitions of any midstream energy projects (including well connections) within five miles of any of our Barnett or Mid-Continent acreage dedications that may from time to time become available to Chesapeake, other than those which were subject to a dedication or similar arrangement as of September 30, 2009, although Chesapeake will not be obligated to accept any offer we make. Our Barnett acreage dedication consists of portions of nine counties in northern Texas, including Johnson and Tarrant counties. Our Mid-Continent acreage dedication consists of portions Arkansas, Kansas, New Mexico, Oklahoma, and Texas. We refer to the five mile areas outside of the acreage dedications as the “proximate areas.”

Upon our receipt of written notice of a proximate area opportunity from Chesapeake, we will have the right, exercisable within either ten days (in the case of individual well connections) or 30 days (in the case of all other proximate area opportunities), to make a first offer for us to pursue such opportunity. Such offer must include, to the extent reasonably practicable, reasonable detail regarding the terms upon which we would be willing to pursue such proximate area opportunity. Chesapeake will have 30 days from the date of delivery of our offer for such proximate area opportunity to accept our offer or to provide us with written notice of its rejection thereof. In the event that we decline to make an offer or Chesapeake rejects our offer, Chesapeake will be free to pursue the proximate area opportunity on its own or in a transaction with an unaffiliated third party, provided that the terms and conditions of any such transaction cannot be more favorable in the aggregate to such participants or to such unaffiliated third party than as are set forth in our offer.

Terminating Third-Party Contract Opportunities . To the extent Chesapeake is a party to any material gas gathering agreement or other material midstream energy services agreement with any third party covering services provided within an acreage dedication or any proximate area and such agreement becomes terminable by Chesapeake at no cost and without liability or is otherwise terminated, our omnibus agreement will require Chesapeake to provide us notice of such terminating third-party contract. Upon receipt of notice of such a terminating third-party contract, we will have the right, exercisable within 60 days, to make an offer stating the terms pursuant to which we would be willing to provide the services provided by such contract. Chesapeake will then have 60 days to accept or reject the terms of such offer. In the event that Chesapeake rejects the offer, it will be free to obtain the services covered by such terminating third-party contract from a third party, provided that such services are provided on terms and conditions no more favorable in the aggregate to such third party than as are set forth in our offer.

Monetization Transaction Opportunities . In the event that Chesapeake proposes to enter into any sale, transfer, disposition, joint venture or other monetization (whether involving assets or equity interests) of any midstream gathering systems and associated infrastructure assets located outside of the acreage dedications and the proximate areas, subject to certain exceptions, Chesapeake will be required to first provide us with notice of such monetization transaction opportunity. Such notice must include any material terms, conditions and details (other than those relating to price, gas gathering and other commercial agreements to the extent not provided to any other third party in connection with the proposed transaction) as would be necessary for us to make a responsive offer to enter into the contemplated monetization transaction, which terms, conditions and details must at a minimum include any terms, conditions and details provided to third parties in connection with the proposed monetization transaction. Upon receipt of such notice, we will have the right, exercisable within 60

 

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days, to make an offer to Chesapeake to enter into the monetization transaction. Chesapeake will then have 60 days to accept or reject the terms of such offer. If we do not make a valid offer in response to any such monetization opportunity, Chesapeake will be free to enter into such monetization opportunity with any third party on terms and conditions no more favorable to such third party than those set forth in the notice of such opportunity provided to us by Chesapeake. In the event that Chesapeake rejects the offer, it will be free to enter into the monetization transaction with a third party, provided that (i) the terms and conditions of the transaction (including those relating to gas gathering and other commercial agreements, but excluding those relating to price) cannot be more favorable in the aggregate to such third party than as are set forth in our offer and (ii) such monetization transaction is at a price equal to no less than 95% of the price set forth in our offer. Notwithstanding the foregoing, Chesapeake will not be required to provide us with a right of first offer with respect to the following types of transactions:

 

   

equity financing transactions by Chesapeake in respect of any midstream gathering systems and/or associated infrastructure located outside of the acreage dedications and the proximate areas, the net proceeds of which are used to finance the construction, development and/or operation of such midstream gathering systems and/or associated infrastructure assets;

 

   

any financing transactions consisting of debt that is non-convertible and non-exchangeable, provided that any such transaction or series of related transactions may include the issuance of equity interests to the parties providing financing or affiliates thereof that in the aggregate constitute less than 20% of the aggregate value of such financing transaction;

 

   

any transactions that would result in a change of control of Chesapeake Energy Corporation or a sale of all or substantially all of the assets of Chesapeake Energy Corporation and its subsidiaries, taken as a whole;

 

   

any sale, joint venture or other monetization of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas in connection with a sale of interests in oil and gas properties (including, but not limited to, volumetric production payments) in which the majority of the assets (by value) are comprised of oil and gas exploration and production assets;

 

   

any transaction that was subject to a right of first refusal, purchase or similar commitment to a third party as of September 30, 2009;

 

   

any exchange, swap or similar property-for-property transaction involving the exchange of any midstream gathering system and/or associated infrastructure assets outside the acreage dedications and the proximate areas for other midstream gathering systems and/or associated infrastructure assets outside the acreage dedications and the proximate areas, to the extent any net cash proceeds to Chesapeake from any such transaction or series of related transactions does not comprise more than 20% of the aggregate value of the assets subject to such transaction or series of related transactions; and

 

   

any sale, transfer or disposition to a 100% affiliate of Chesapeake Energy Corporation that remains a 100% affiliate of Chesapeake Energy Corporation at all times following such sale, transfer or disposition.

With respect to the fifth bullet listed above, a third party has a right of first refusal covering Chesapeake’s midstream assets in the Marcellus Shale that has priority over our right of first offer applicable to any monetization of those assets by Chesapeake.

 

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Services Arrangement . The table below reflects the categories of expenses for which we will be obligated to reimburse Chesapeake pursuant to the omnibus agreement, and, by category, sets forth an estimate of the amount that we will pay to Chesapeake for the twelve months ending December 31, 2010 consistent with the forecast for such period set forth in “Our Cash Distribution Policy and Restrictions on Distributions—Estimated Adjusted EBITDA for the Twelve Months Ending December 31, 2010.”

 

     Estimates for the Twelve
Months Ending
December 31, 2010
     (In millions)

Reimbursement for general and administrative services

   $ 18

Reimbursement for additional services

   $ 9

General and Administrative Services and Reimbursement . Under the omnibus agreement, Chesapeake will perform centralized corporate functions for us, including human resources, information technology, treasury, risk management, legal, executive management, security, environmental, regulatory, production control, supervisory control and data application systems, gas measurement, internal audit, accounting, legal services, certain investor relations functions, volume control and contract management support. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake on a monthly basis for the time and materials actually spent in performing general and administrative services on our behalf. Our reimbursement to Chesapeake of such general and administrative expenses in any given month will be subject to a cap in an amount equal to $0.03 per Mcf multiplied by the volume (measured in Mcf) of natural gas that we gather, transport or process, subject to an annual escalation. The $0.03 per Mcf cap will be subject to an annual upward adjustment each year as of October 1 equal to 50% of any increase in the Consumer Price Index and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in the general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented after the closing of the offering.

The cap contained in the omnibus agreement does not apply to our direct general and administrative expenses or incremental general and administrative expenses that we expect to incur or to be allocated to us as a result of becoming a publicly traded partnership or the additional services reimbursement described below.

Additional Services and Reimbursement . At our request, Chesapeake will also agree to provide us with certain additional services under the omnibus agreement, including engineering, construction, procurement, business analysis, commercial, cartographic and other similar services to the extent they are not already provided by the seconded employees. In return for such additional services, our general partner has agreed to reimburse Chesapeake on a monthly basis an amount equal to the time and materials actually spent in performing the additional services. The reimbursement for additional services is not subject to the general and administrative services reimbursement cap.

Chesapeake will agree to perform all services under the relevant provisions of the omnibus agreement using at least the same level of care, quality, timeliness and skill as it does for itself and its affiliates and with no less than the same degree of care, quality, timeliness and skill as its past practice in performing the services for itself and our business during the one year period prior to September 30, 2009. In any event, Chesapeake shall perform such services using no less than a reasonable level of care in accordance with industry standards.

In connection with the services arrangement, we have agreed to reimburse GIP for certain costs incurred by GIP in connection with assisting us in the operation of our business. For the year ended December 31, 2010, we estimate that we will reimburse GIP approximately $1 million for these support services.

The term of the provision of such services will extend for additional twelve month periods unless any party provides 180 days’ prior written notice otherwise prior to the expiration of the initial term ending December 31, 2011 or the applicable twelve month period; provided that our general partner has the right to extend the term of

 

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the services agreement through June 30, 2012 regardless of any other party providing notice to terminate on December 31, 2011. In such a situation, the services agreement would automatically terminate on June 30, 2012.

Indemnification. Pursuant to the omnibus agreement, we will be entitled to indemnification for certain liabilities and we will be required to indemnify Chesapeake for certain liabilities.

Employee Secondment Agreement

Concurrent with the closing of this offering, Chesapeake Energy Corporation, certain of its affiliates and our general partner will enter into an amended and restated employee secondment agreement pursuant to which we anticipate that specified employees of Chesapeake will be seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Additionally, all of our executive officers other than our chief executive officer, Mr. Stice, will be seconded to our general partner pursuant to this agreement. Our general partner will, subject to specified exceptions and limitations, reimburse Chesapeake on a monthly basis for all costs and expenses Chesapeake incurs relating to such seconded employees, including the cost of their salaries, bonuses and employee benefits, including 401(k), restricted stock grants and health insurance and certain severance benefits. For the twelve months ending December 31, 2010, we anticipate that our general partner will reimburse Chesapeake approximately $30 million for the services rendered by such seconded employees during such period.

The initial term of the employee secondment agreement extends through September 30, 2014. The term will automatically extend for additional twelve month periods unless any party provides 90 days’ prior written notice otherwise prior to the expiration of the initial term or the applicable twelve month period. Our general partner may terminate the agreement at any time upon 90 days’ prior written notice.

Employee Transfer Agreement

In order to provide for an efficient transition of seconded employees from their current joint employment relationship with our general partner and Chesapeake in the event that our general partner elects to establish a standalone workforce, concurrent with the closing of this offering, Chesapeake Energy Corporation, certain of its affiliates and our general partner will enter into an amended and restated employee transfer agreement pursuant to which our general partner will agree to maintain certain compensation and benefits standards for seconded employees to whom our general partner makes offers of employment. Among other things, the employee transfer agreement will limit the ability of our general partner to hire seconded employees from Chesapeake to situations where our general partner offers such seconded employee a base salary or hourly base wages, as applicable, equal or greater than that which Chesapeake provides such seconded employee at the time of transfer and other compensation and benefits that, in the aggregate, are substantially comparable to those provided to such seconded employee at such time. Additionally, in the event of such an employee transfer, for a period of not less than twelve months thereafter, we will be obligated to maintain the base salary or hourly wages, as applicable, for such transferred employee of no less than that paid to such transferred employee immediately prior to the transfer date and other compensation and benefits for such transferred employee that, in the aggregate, are substantially comparable to those in effect immediately prior to the transfer date.

The employee transfer agreement will have an indefinite term. However, the agreement is terminable (i) by the parties upon their mutual agreement, (ii) by any party upon another party’s failure to cure a material breach for 120 days, or (iii) by any party in the event that another party becomes insolvent.

Shared Services Agreement

In return for the services of Mr. Stice as the chief executive officer of our general partner, our general partner has entered into a shared services agreement with Chesapeake Energy Corporation pursuant to which our general partner has agreed to reimburse certain of the costs and expenses incurred by Chesapeake Energy

 

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Corporation in connection with Mr. Stice’s employment. Our general partner is generally required, subject to certain exceptions, to reimburse Chesapeake Energy Corporation for 50% of the costs and expenses of the salary, benefits and other costs (including 401(k), insurance and other benefits) currently afforded to Mr. Stice in connection with his employment agreement with Chesapeake Energy Corporation. The reimbursement obligations of our general partner will continue for so long as Mr. Stice is employed by both our general partner and Chesapeake Energy Corporation.

Gas Gathering Agreements

We have entered into 20-year natural gas gathering agreements with certain subsidiaries of Chesapeake and with Total pursuant to which we provide gathering, treating, compression and dehydration services, as applicable, for natural gas delivered by Chesapeake and Total to our gathering systems in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region. Total Holdings USA Inc., a wholly owned subsidiary of Total S.A., has guaranteed the obligations of Total Gas & Power North America, Inc. and Total E&P USA, Inc. under the Total gas gathering agreement. These agreements provide us with dedication of all of the natural gas owned or controlled by Chesapeake and Total and produced from or attributable to existing and future wells located on oil, gas and mineral leases covering lands within the acreage dedications, excluding (i) any oil, gas and/or mineral leases purchased, in the case of Chesapeake after September 30, 2009, and in the case of Total after February 1, 2010, that were, at the time of purchase, subject to dedication to another gas gathering system not owned and operated by Chesapeake, and such dedication was not entered into in connection with such acquisition; (ii) certain reserved properties specified in the gas gathering agreement; and (iii) other non-material properties dedicated as of September 30, 2009 in the case of Chesapeake, or as of February 1, 2010, in the case of Total to another gas gathering system not owned and operated by Chesapeake.

Pursuant to our gas gathering agreements, Chesapeake and Total have committed to deliver specified minimum volumes of natural gas to our gathering systems that take production from the Barnett Shale for each year through December 31, 2018 and for the six month period ending June 30, 2019. The aggregate minimum volume commitments, approximately 75% of which will be attributed to Chesapeake and approximately 25% of which will be attributed to Total, begin at approximately 418 Bcf for the year ending December 31, 2010 (or an average of approximately 1.14 Bcf/d) and increase on an annual basis pursuant to the terms of the gas gathering agreement to approximately 493 Bcf for the year ending December 31, 2018 (or an average of 1.37 Bcf/d). Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Gas Gathering Agreements.” The minimum volume commitments may be reduced in certain instances, including a force majeure event affecting a system, a delayed connection or to the extent a system is unavailable due to inspections, alterations or repairs in excess of five days per month. In the event either Chesapeake or Total does not meet its minimum volume commitment, as adjusted in certain instances, to us for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each Mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitment of such party for the six months ending June 30, 2019 and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the immediately preceding period.

We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake and Total in the acreage dedications. Chesapeake and Total are required to provide us notice of new drilling pads and wells operated by Chesapeake or Total in the acreage dedications. During the minimum volume commitment period and subject to certain conditions specified in the gas gathering agreements, we are generally required to connect new operated drilling pads in the Barnett acreage dedication by the later of the date the wells commence

 

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production or 21 months after the date of the connection notice and, until June 30, 2019, to use our commercially reasonable efforts to connect new operated wells in the Mid-Continent area by the later of the date the wells commence production or 60 days after the date of the connection notice. If we fail to complete a connection in the Barnett acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After June 30, 2019, we only are required to make connections in the acreage dedications to new drilling pads and wells if we believe that the then current fees would allow us to earn an acceptable return on our investment, and if we decline to make a connection, Chesapeake and Total have certain rights to reimburse us for our connection costs or to request a release from the gathering agreement dedication of the affected wells. Chesapeake and Total also are required to notify us of their wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering systems. If we decline to make a connection to a non-operated well, Chesapeake or Total, as the case may be, have certain rights to have the well released from the dedication under the gas gathering agreement.

A maximum daily quantity is also in effect with respect to the gathering systems that take production from the Barnett Shale. Generally, once daily volumes equal the maximum quantity specified for a particular system, we are no longer obligated to accept natural gas on such system. Under certain circumstances, however, where excess capacity is then available on an applicable gathering system, we may be required to accept such natural gas to the extent available and to provide “Priority 3 Service” with respect to such volumes. In most instances (and, where applicable, up to the maximum daily quantity), Chesapeake and Total are entitled to “Priority 1 Service.” If capacity on a system is curtailed or reduced, or capacity is otherwise insufficient, the holders of Priority 1 Service will be curtailed last. Subject to certain limitations, we may commingle Chesapeake’s and Total’s natural gas with the natural gas of third parties.

Volumetric losses in Chesapeake’s or Total’s natural gas attributable to lost and unaccounted for natural gas, as well as volumetric reductions related to the use of fuel gas for gathering, compression, dehydrating, processing and treating, are, with respect to a particular gathering system, shared and allocated among Chesapeake, Total and other third-party shippers in the proportion that each party delivers gas to such system. We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel gas and lost and unaccounted for gas and electricity on our systems with respect to its volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed-upon cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, lost or unaccounted for, or electricity in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

The agreements are fee-based, and we are paid a specified fee per Mcf for natural gas received on our gathering systems. The particular fees, which are subject to an automatic annual escalator at the beginning of each year, differ from one system to another and, in some cases, are based in part upon receipt point pressures. At specified intervals, we and each of Chesapeake and Total have the right to seek a redetermination of the fees for service on the Barnett gathering system. Such rights may be exercised during a six-month period beginning September 30, 2011 and a two-year period beginning September 30, 2014. A fee redetermination with respect to our Barnett Shale region under either agreement will apply to volumes from Chesapeake and Total under both agreements. The cumulative upward or downward fee adjustment for the Barnett Shale region is capped at 27.5% of the initial weighted average Barnett Shale fee (as escalated) as specified in the gas gathering agreement. The fee redetermination mechanism was designed to support a return on our invested capital as we meet our obligation to connect our customers’ operated wells to our gathering systems. An example of such variation may be the variation in fees generated on those systems where the fee is based in part upon receipt point pressures. If a fee redetermination is requested, we will determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period

 

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made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. If we and Chesapeake or Total, as applicable, do not agree upon a redetermination of the Barnett Shale fee within 30 days of receipt of the request for the redetermination, an industry expert will be selected to determine adjustments to the Barnett Shale fee. A redetermined Barnett Shale fee will go into effect on the first day of the month following the date on which the adjusted fee is finally determined. The Mid-Continent fees will be redetermined at the beginning of each year through 2019. We will determine an adjustment to fees for the gathering systems in the region with Chesapeake based on the factors specified in the gas gathering agreement, including, but not limited to differences between our actual revenues, capital expenditures and compression expenses as of the redetermination date and the scheduled estimates of these amounts for the period ending June 30, 2019, referred to as the Mid-Continent redetermination period, made as of September 30, 2009. The annual upward or downward fee adjustment for the Mid-Continent region is capped at 15% of the then current fees at the time of redetermination.

Chesapeake continues to own the gathering system located on the property leased from the Dallas-Fort Worth (“DFW”) Airport Authority in the Barnett Shale region, and we have been engaged to operate and maintain this gathering system. We receive as a fee for providing the operation and maintenance services an amount equal to all revenues derived from the operation of the DFW gathering system while we serve as the operator, including the fees paid by Chesapeake and Total under our gas gathering agreements. If our right to operate and maintain the DFW gathering system is terminated, Chesapeake is obligated to make a termination payment to us that equals the economic benefits we would have received if such termination had not occurred and to indemnify us for any other losses arising from such early termination.

The primary terms of the agreements continue through June 30, 2029, after which the agreements continue in effect on a year-to-year basis unless terminated by either party. We may terminate our gas gathering agreement with Chesapeake or Total if Chesapeake or Total, as applicable, fails to perform any of its material obligations, such failure is not excused by force majeure events and such failure is not remedied (or remedial action commenced) during a 60-day cure period. Chesapeake or Total may terminate if we fail to perform any of our material obligations. However, if our failure relates to only one or more facilities or gathering systems, Chesapeake or Total may terminate only as to such facility or system. Where Chesapeake or Total fails to pay us an undisputed amount when due, we may terminate if such failure is not remedied within 15 business days after we provide notice to Chesapeake or Total of such failure. We have entered into a guaranty with Chesapeake Energy Corporation relating to, among other agreements, our gas gathering agreement with certain of its affiliates. The guaranty provided by Chesapeake Energy Corporation is a guaranty of payment and performance and not of collection.

In the event that either Chesapeake or Total sells, transfers or otherwise disposes to a third party properties within the acreage dedication in our Barnett Shale region and, solely with respect to Chesapeake, our Mid-Continent region, it will be required to cause the third party to either enter into our existing gas gathering agreement with Chesapeake or Total, as applicable, or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total, as applicable.

Gas Compressor Master Rental and Servicing Agreement

We have entered into a gas compressor master rental and servicing agreement with MidCon Compression, LLC, a wholly-owned indirect subsidiary of Chesapeake Energy Corporation, pursuant to which MidCon Compression has agreed to lease to us certain compression equipment that we use to compress gas gathered on our gathering systems and provide certain related services. In return for the lease of such equipment, we have agreed to pay specified monthly rates per specified compression units, subject to an annual escalator to be applied on October 1 st of each year and a redetermination of such specified monthly rates to market rates effective no later than October 1, 2016. Under the compression agreement, we have granted MidCon

 

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Compression the exclusive right to lease and rent compression equipment to us in the acreage dedications through September 30, 2016. Thereafter, we will have the right to continue leasing such equipment through September 30, 2019 at market rental rates to be agreed upon between the parties or to lease compression equipment from unaffiliated third parties. MidCon Compression guarantees to us that the leased compressors will meet specified run time and throughput performance guarantees. The monthly rental rates are reduced for any leased equipment that does not meet these guarantees.

We are obligated to maintain general liability and property insurance, including machinery breakdown insurance with respect to the leased equipment. In addition, MidCon Compression has agreed to provide us with emission testing and other related services at monthly rates. We may terminate these services upon not less than six months notice, and MidCon Compression may terminate these services at any time after September 30, 2011 upon not less than six months notice.

The compression agreement expires on September 30, 2019 but will continue from year to year thereafter, unless terminated by us no less than 60 days prior to the end of the term or any year thereafter. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

Inventory Purchase Agreement

We have entered into an inventory purchase agreement pursuant to which we have agreed to purchase from Chesapeake, in each case on terms and conditions to be mutually agreed upon by Chesapeake and us, our first $60.0 million of requirements of pipes that are useful in the conduct of the natural gas gathering, compression, dehydrating, treating and transportation business at a specified price per ton.

Marketing and Noncompete Agreement

Pursuant to a marketing and noncompete agreement, we have agreed to appoint Chesapeake Energy Marketing, Inc., a wholly-owned indirect subsidiary of Chesapeake Energy Corporation (which we refer to as CEMI), as our agent to purchase, at our request, gas on behalf of us, at agreed market responsive prices and for an agreed marketing fee, to settle accrued gas imbalances on our gathering systems. As consideration for such agreement, we have agreed to not engage in activities to purchase or market natural gas in the acreage dedications if CEMI or its affiliates are then performing, or willing to perform, such activities on our behalf. Additionally, each of CEMI and Chesapeake Exploration L.L.C., Chesapeake Louisiana L.P. and DD Jet Limited, LLP, each wholly-owned indirect subsidiaries of Chesapeake Energy Corporation, has agreed not to, and to cause Chesapeake not to, directly or indirectly, engage in or participate in activities to gather or transport natural gas in the acreage dedications, whether for their own account or on behalf of third parties.

The marketing and noncompete agreement expires on September 30, 2019 but will continue from month to month thereafter, unless terminated by either party upon no less than 30 days’ prior notice. Additionally, either party may terminate in specified circumstances, including upon the other party’s failure to perform material obligations under the compression agreement if such failure is not cured within 60 days after notice thereof.

Master Recoupment, Netting and Setoff Agreement

We have entered into a master recoupment, netting and setoff agreement with Chesapeake Energy Corporation and certain of its subsidiaries. The recoupment agreement provides for the netting of fees, liquidated damages and other charges between the parties to certain “covered agreements,” including the gas gathering agreement with Chesapeake, the gas compressor rental and servicing agreement, the omnibus agreement (excluding matters related to business opportunities), the employee secondment agreement and the employee transfer agreement. The recoupment agreement provides for the parties’ right to recoup, net and setoff accrued and unpaid fees, reimbursements, late payment charges and interest, and liquidated damages for breach or early

 

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termination pursuant to specified obligations arising under the terms of the covered agreements and losses, damages and other amounts to the extent agreed by the parties or provided by a court order. Recoupment, netting and setoff rights are triggered by a “recoupment event,” defined as the failure to pay an accrued payment obligation or obligations exceeding $100,000 under a covered agreement. Under the agreement, if a “triggering event,” defined as bankruptcy or insolvency, occurs, the non-bankrupt/insolvent party has the right to hold funds due from it to the bankrupt/insolvent party as an offset to liquidated amounts due from the bankrupt/insolvent party to the non-bankrupt/insolvent party, pending resolution of the parties’ rights under the recoupment agreement or common law. This agreement will terminate in the event there are fewer than two “covered agreements” in effect, or earlier upon written agreement of the parties.

Surety Bond Indemnification Agreement

We have agreed to indemnify Chesapeake and certain affiliates of Chesapeake against any loss or expense with respect to certain surety bonds issued for our benefit and for which we are obligated to provide indemnity insurance to Chesapeake. We may also be required to indemnify Chesapeake in connection with future surety bond issuances made for our benefit. Our currently outstanding surety bonds relate to certain well, pipeline and litigation obligations in New Mexico, Oklahoma and Texas. These indemnification obligations will not expire until all bond obligations for which we are liable for indemnification to Chesapeake are released.

Trademark License Agreement

We have entered into a trademark license agreement with Chesapeake Energy Corporation pursuant to which it has agreed to grant to us a license to use the mark “Chesapeake” in the trade name and service mark “Chesapeake Midstream Partners.” Such license is a royalty-free, fully paid up, nonexclusive and nontransferable right and license to use such marks solely in connection with the midstream natural gas business. Subject to certain exceptions, the trademark license agreement will continue until December 31, 2019. Either party may terminate in the event of a material breach by the other party that is not cured within 30 days of written notice thereof.

Registration Rights Agreement

In connection with the closing of this offering, we will enter into a registration rights agreement with Chesapeake and GIP pursuant to which we will grant each of Chesapeake and GIP certain demand and “piggyback” registration rights. Under the registration rights agreement, each of Chesapeake and GIP will have the right to require us to file a registration statement for the public sale of all of the common and subordinated units owned by it any time after six months following the date the SEC declares the registration statement of which this prospectus forms a part effective. In addition, if we sell any common units in a registered underwritten offering, each of Chesapeake and GIP will have the right to include its common units in that offering. The underwriters of any such offering will have the right to limit the number of common units to be included in such sale.

We will pay all expenses relating to any demand or piggyback registration, except for underwriters or brokers’ commission or discounts.

 

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CONFLICTS OF INTEREST AND FIDUCIARY DUTIES

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including Chesapeake, GIP and Chesapeake Midstream Ventures, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, might constitute breaches of its fiduciary duty.

Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if the resolution of the conflict is:

 

   

approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

 

   

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;

 

   

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

   

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. In connection with a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the partnership.

Conflicts of interest could arise in the situations described below, among others.

Neither our partnership agreement nor any other agreement requires Chesapeake, GIP and/or Chesapeake Midstream Ventures to pursue a business strategy that favors us or utilizes our assets or dictates what markets to pursue or grow. Directors of Chesapeake, GIP and Chesapeake Midstream Ventures have a fiduciary duty to make these decisions in the best interests of the owners of Chesapeake, GIP and Chesapeake Midstream Ventures, as applicable, which may be contrary to our interests.

Because certain of the directors of our general partner are also directors and/or officers of Chesapeake, GIP and/or Chesapeake Midstream Ventures and their affiliates, such directors may have fiduciary duties to Chesapeake, GIP and/or Chesapeake Midstream Ventures, as applicable, that may cause them to pursue business

 

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strategies that disproportionately benefit Chesapeake, GIP and/or Chesapeake Midstream Ventures, as applicable, or which otherwise are not in our best interests.

Our general partner and its affiliates are allowed to take into account the interests of parties other than us in resolving conflicts of interest.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples include our general partner’s limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership.

The chief executive officer of our general partner will also devote a portion of his time to the business of Chesapeake and will be compensated by Chesapeake accordingly.

Mr. Stice, the chief executive officer of our general partner is also an employee of Chesapeake and will devote a portion of his time to our business and affairs. We will also utilize a significant number of employees of Chesapeake to operate our business and for which we will reimburse Chesapeake under our employee secondment agreement, and we will reimburse Chesapeake for certain general and administrative expenses pursuant to our omnibus agreement, subject to the cap specified therein. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.” Our general partner and Chesapeake will also conduct businesses and activities of their own in which we will have no economic interest. If these separate activities are significantly greater than our activities, there could be material competition for the time and effort of the chief executive officer of our general partner and other Chesapeake personnel.

Our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of its fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of our general partner’s fiduciary duty. For example, our partnership agreement:

 

   

provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning it believed that the decision was in the best interest of our partnership;

 

   

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of the common unitholders must either be (i) on terms no less favorable to us than those generally provided to or available from unrelated third parties or (ii) “fair and reasonable” to us, as determined by our general partner in good faith, provided that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

 

   

provides that our general partner and its officers and directors will not be liable for monetary damages to us, or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers or directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct.

 

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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or with respect to which our general partner has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 

   

the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into our securities, and the incurring of any other obligations;

 

   

the purchase, sale or other acquisition or disposition of our securities, or the issuance of additional options, rights, warrants and appreciation rights relating to our securities;

 

   

the mortgage, pledge, encumbrance, hypothecation or exchange of any or all of our assets;

 

   

the negotiation, execution and performance of any contracts, conveyances or other instruments;

 

   

the distribution of our cash;

 

   

the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

 

   

the maintenance of insurance for our benefit and the benefit of our partners;

 

   

the formation of, or acquisition of an interest in, the contribution of property to, and the making of loans to, any limited or general partnership, joint venture, corporation, limited liability company or other entity;

 

   

the control of any matters affecting our rights and obligations, including the bringing and defending of actions at law or in equity, otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense, the settlement of claims and litigation;

 

   

the indemnification of any person against liabilities and contingencies to the extent permitted by law;

 

   

the making of tax, regulatory and other filings, or the rendering of periodic or other reports to governmental or other agencies having jurisdiction over our business or assets; and

 

   

the entering into of agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

Our partnership agreement provides that our general partner must act in “good faith” when making decisions on our behalf, and our partnership agreement further provides that in order for a determination to be made in “good faith,” our general partner must believe that the determination is in our best interests. Please read “The Partnership Agreement—Voting Rights” for information regarding matters that require unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

The amount of cash that is available for distribution to our unitholders is affected by the decisions of our general partner regarding such matters as:

 

   

the amount and timing of asset purchases and sales;

 

   

cash expenditures;

 

   

borrowings;

 

   

the issuance of additional units; and

 

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the creation, reduction or increase of reserves in any quarter.

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert into common units.

In addition, our general partner may use an amount, initially equal to $              million, which would not otherwise constitute available cash from operating surplus, in order to permit the payment of cash distributions on its units and incentive distribution rights. All of these actions may affect the amount of cash distributed to our unitholders and our general partner and may facilitate the conversion of subordinated units into common units. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions.”

In addition, borrowings by us and our affiliates do not constitute a breach of any duty owed by our general partner to our unitholders, including borrowings that have the purpose or effect of:

 

   

enabling our general partner or its affiliates to receive distributions on any subordinated units held by them or the incentive distribution rights; or

 

   

accelerating the expiration of the subordination period.

For example, in the event we have not generated sufficient cash from our operations to pay the minimum quarterly distribution on our common and subordinated units, our partnership agreement permits us to borrow funds, which would enable us to make this distribution on all of our outstanding units. Please read “Provisions of our Partnership Agreement Related to Cash Distributions—Subordination Period.”

Our partnership agreement provides that we and our subsidiaries may borrow funds from our general partner and its affiliates. Our general partner and its affiliates may borrow funds from us, or our operating company and its operating subsidiaries.

Our general partner determines which of the costs it incurs on our behalf are reimbursable by us.

We will reimburse our general partner and its affiliates for the costs incurred in managing and operating us, including costs incurred both by it and on its behalf pursuant to services arrangements with Chesapeake in rendering corporate staff and support services to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or from entering into additional contractual arrangements with any of these entities on our behalf.

Our partnership agreement allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Neither our partnership agreement nor any of the other agreements, contracts or arrangements between us, on the one hand, and our general partner and its affiliates, on the other hand, that will be in effect as of the closing of this offering, will be the result of arm’s-length negotiations. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates that are entered into following the closing of this offering may not be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee of our general partner may make a determination on our behalf with respect to such arrangements.

Our general partner will determine, in good faith, the terms of any such transactions entered into after the closing of this offering.

 

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Our general partner and its affiliates will have no obligation to permit us to use any of its or its affiliates’ facilities or assets, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner or its affiliates to enter into any contracts of this kind.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that counterparties to such agreements have recourse only against our assets, and not against our general partner or its assets. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability.

Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of our common units.

Our general partner may exercise its right to call and purchase common units, as provided in our partnership agreement, or may assign this right to one of its affiliates or to us. Our general partner is not bound by fiduciary duty restrictions in determining whether to exercise this right. As a result, a common unitholder may be required to sell his common units at an undesirable time or price. Please read “The Partnership Agreement—Limited Call Right.”

Our general partner controls the enforcement of its and its affiliates’ obligations to us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

The attorneys, independent accountants and others who have performed services for us regarding this offering have been retained by our general partner. Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the holders of common units in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

 

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We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when we are experiencing declines in our aggregate cash distributions or at a time when our general partner expects that we will experience declines in our aggregate cash distributions in the foreseeable future. In such situations, our general partner may be experiencing, or may expect to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our common units, which are entitled to specified priorities with respect to our distributions and which therefore may be more advantageous for the general partner to own in lieu of the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then current business environment. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights. Please read “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner Interest and Incentive Distribution Rights.”

Fiduciary Duties

Our general partner is accountable to us and our unitholders as a fiduciary. Fiduciary duties owed to unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, modify, restrict or expand the fiduciary duties otherwise owed by a general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these restrictions to allow our general partner or its affiliates to engage in transactions with us that would otherwise be prohibited by state-law fiduciary duty standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because our general partner’s board of directors will have fiduciary duties to manage our general partner in a manner that is beneficial to its owners, as well as to our unitholders. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable our general partner to take into consideration all parties involved in the proposed action, so long as the resolution is fair and reasonable to us. These modifications also enable our general partner to attract and retain experienced and capable directors. These modifications are detrimental to our unitholders because they restrict the remedies available to unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interest. The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State-law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where a conflict of interest is present.

 

Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues about compliance with fiduciary duties or

 

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applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These standards reduce the obligations to which our general partner would otherwise be held.

Our partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest that are not approved by a vote of common unitholders and that are not approved by the conflicts committee of the board of directors of our general partner must be

 

   

on terms no less favorable to us than those generally being provided to, or available from, unrelated third parties; or

 

   

“fair and reasonable” to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us).

If our general partner does not seek approval from the conflicts committee and the board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet points above, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which our general partner would otherwise be held.

In addition to the other more specific provisions limiting the obligations of our general partner, our partnership agreement further provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that our general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

 

Rights and remedies of unitholders

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of himself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

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By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render the partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. We must also provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC, such indemnification is contrary to public policy and, therefore, unenforceable. Please read “The Partnership Agreement—Indemnification.”

 

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DESCRIPTION OF THE COMMON UNITS

The Units

The common units and the subordinated units are separate classes of limited partner interests in us. The holders of units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common and subordinated units in and to partnership distributions, please read this section and “Our Cash Distribution Policy and Restrictions on Distributions.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, please read “The Partnership Agreement.”

Transfer Agent and Registrar

Duties . Computershare Trust Company, N.A. will serve as the registrar and transfer agent for the common units. We will pay all fees charged by the transfer agent for transfers of common units except the following that must be paid by unitholders:

 

   

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

   

special charges for services requested by a common unitholder; and

 

   

other similar fees or charges.

There will be no charge to unitholders for disbursements of our cash distributions. We will indemnify the transfer agent, its agents and each of their stockholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

Resignation or Removal . The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If no successor has been appointed and accepted the appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

 

   

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

   

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

   

is deemed to have given the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements that we are entering into in connection with our formation and this offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

 

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We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities that are transferable according to the laws governing the transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

 

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THE PARTNERSHIP AGREEMENT

The following is a summary of the material provisions of our partnership agreement. The form of our partnership agreement is included in this prospectus as Appendix A. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

   

with regard to distributions of available cash, please read “Provisions of our Partnership Agreement Relating to Cash Distributions;”

 

   

with regard to the fiduciary duties of our general partner, please read “Conflicts of Interest and Fiduciary Duties;”

 

   

with regard to the transfer of common units, please read “Description of the Common Units—Transfer of Common Units;” and

 

   

with regard to allocations of taxable income and taxable loss, please read “Material Tax Consequences.”

Organization and Duration

Our partnership was organized in January 2010 and will have a perpetual existence.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided, that our general partner shall not cause us to engage, directly or indirectly, in any business activity that the general partner determines would cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than the business of gathering, compressing, treating and transporting natural gas, our general partner has no current plans to do so and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. Our general partner is generally authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Power of Attorney

Each limited partner, and each person who acquires a unit from a unitholder, by accepting the common unit, automatically grants to our general partner and, if appointed, a liquidator, a power of attorney to, among other things, execute and file documents required for our qualification, continuance or dissolution. The power of attorney also grants our general partner the authority to amend, and to make consents and waivers under, our partnership agreement.

Cash Distributions

Our partnership agreement specifies the manner in which we will make cash distributions to holders of our common units and other partnership securities as well as to our general partner in respect of its general partner interest and its incentive distribution rights. For a description of these cash distribution provisions, please read “Provisions of our Partnership Agreement Relating to Cash Distributions.”

 

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Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

If we issue additional units, our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner’s 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Our general partner will be entitled to make a capital contribution in order to maintain its 2.0% general partner interest in the form of the contribution to us of common units based on the current market value of the contributed common units.

Voting Rights

The following is a summary of the unitholder vote required for approval of the matters specified below. General partner units are not deemed outstanding units for purposes of voting rights and such units represent a non-voting general partner interest. Matters that require the approval of a “unit majority” require:

 

   

during the subordination period, the approval of a majority of the common units, excluding those common units held by our general partner and its affiliates, and a majority of the subordinated units, voting as separate classes; and

 

   

after the subordination period, the approval of a majority of the common units.

In voting their common and subordinated units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

 

Issuance of additional units

No approval right.

 

Amendment of the partnership agreement

Certain amendments may be made by the general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. Please read “—Amendment of the Partnership Agreement.”

 

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

Unit majority in certain circumstances. Please read “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. Please read “—Termination and Dissolution.”

 

Continuation of our business upon dissolution

Unit majority. Please read “—Termination and Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to March 31, 2020 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

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Removal of our general partner

Not less than 66  2 / 3 % of the outstanding units, voting as a single class, including units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

 

Transfer of our general partner interest

Our general partner may transfer all, but not less than all, of its general partner interest in us without a vote of our unitholders to an affiliate or another person in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in other circumstances for a transfer of the general partner interest to a third party prior to March 31, 2020. Please read “—Transfer of General Partner Units.”

 

Transfer of incentive distribution rights

Except for transfers to an affiliate or to another person as part of our general partner’s merger or consolidation, sale of all or substantially all of its assets or the sale of all of the ownership interests in our general partner, the approval of a majority of the common units, excluding common units held by our general partner and its affiliates, is required in most circumstances for a transfer of the incentive distribution rights to a third party prior to March 31, 2020. Please read “—Transfer of Incentive Distribution Rights.”

 

Transfer of ownership interests in our general partner

No approval required at any time. Please read “—Transfer of Ownership Interests in the General Partner.”

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that he otherwise acts in conformity with the provisions of the partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. However, if it were determined that the right, or exercise of the right, by the limited partners as a group:

 

   

to remove or replace our general partner;

 

   

to approve some amendments to our partnership agreement; or

 

   

to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining

 

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the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to the partnership, except that such person is not obligated for liabilities unknown to him at the time he became a limited partner and that could not be ascertained from the partnership agreement.

Our subsidiaries conduct business in five states and we may have subsidiaries that conduct business in other states in the future. Maintenance of our limited liability as a member of the operating company may require compliance with legal requirements in the jurisdictions in which the operating company conducts business, including qualifying our subsidiaries to do business there.

Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating company or otherwise, it were determined that we were conducting business in any state without compliance with the applicable limited partnership or limited liability company statute, or that the right or exercise of the right by the limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Securities

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units, subordinated units or other partnership securities. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions of available cash. In addition, the issuance of additional common units or other partnership securities may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership securities that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity securities, which may effectively rank senior to the common units.

Upon issuance of additional partnership securities (other than the issuance of partnership securities issued in connection with a reset of the incentive distribution target levels relating to our general partner’s incentive distribution rights or the issuance of partnership securities upon conversion of outstanding partnership securities), our general partner will be entitled, but not required, to make additional capital contributions to the extent necessary to maintain its 2.0% general partner interest in us. Our general partner’s 2.0% interest in us will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest. Moreover, our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership securities whenever, and on the same terms that, we issue those securities

 

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to persons other than our general partner and its affiliates, to the extent necessary to maintain the percentage interest of the general partner and its affiliates, including such interest represented by common and subordinated units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights to acquire additional common units or other partnership securities.

Amendment of the Partnership Agreement

General . Amendments to our partnership agreement may be proposed only by or with the consent of our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments . No amendment may be made that would:

 

   

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

   

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld at its option.

The provision of our partnership agreement preventing the amendments having the effects described in the clauses above can be amended upon the approval of the holders of at least 90.0% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Upon completion of the offering, affiliates of our general partner will own approximately     % of our outstanding common and subordinated units.

No Unitholder Approval . Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

   

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

   

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

   

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor the operating company nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

 

   

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

   

an amendment that our general partner determines to be necessary or appropriate for the authorization of additional partnership securities or the right to acquire partnership securities, including any amendment that our general partner determines is necessary or appropriate in connection with:

 

   

the adjustments of the minimum quarterly distribution, first target distribution, second target distribution and third target distribution in connection with the reset of our general partner’s

 

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incentive distribution rights as described under “Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner’s Right to Reset Incentive Distribution Levels,” or

 

   

any modification of the incentive distribution rights made in connection with the issuance of additional partnership securities or rights to acquire partnership securities, provided that, any such modifications and related issuance of partnership securities have received approval by a majority of the members of the conflicts committee of our general partner;

 

   

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

   

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

   

any amendment that our general partner determines to be necessary or appropriate for the formation by us of, or our investment in, any corporation, partnership or other entity, as otherwise permitted by our partnership agreement;

 

   

a change in our fiscal year or taxable year and related changes;

 

   

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

   

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

 

   

do not adversely affect the limited partners (or any particular class of limited partners) in any material respect;

 

   

are necessary or appropriate to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

   

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

   

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of units under the provisions of our partnership agreement; or

 

   

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval . Our general partner will not be required to obtain an opinion of counsel that an amendment will neither result in a loss of limited liability to the limited partners nor result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units, voting as a single class, unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under applicable law of any of our limited partners.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

 

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Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on our behalf the sale, exchange or other disposition of all or substantially all of the assets of our subsidiaries. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval. Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in a material amendment to the partnership agreement, each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership securities immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, our general partner has received an opinion of counsel regarding limited liability and tax matters and the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Termination and Dissolution

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

 

   

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

   

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

   

the entry of a decree of judicial dissolution of our partnership; or

 

   

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or its withdrawal or removal following the approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

   

the action would not result in the loss of limited liability of any limited partner; and

 

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neither our partnership, our operating company nor any of our other subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless we are continued as a new limited partnership, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Provisions of our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to March 31, 2020 without obtaining the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates, and furnishing an opinion of counsel regarding limited liability and tax matters. On or after March 31, 2020, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding common units are held or controlled by one person and its affiliates, other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner, in some instances, to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. Please read “—Transfer of General Partner Units” and “—Transfer of Incentive Distribution Rights.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. Please read “—Termination and Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66  2 / 3 % of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units, voting as a class, and the outstanding subordinated units, voting as a class. The ownership of more than 33  1 / 3 % of the outstanding units by our general partner and its affiliates would give them the practical ability to prevent our general partner’s removal. At the closing of this offering, affiliates of our general partner will own     % of our outstanding common and subordinated units.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and the units held by our general partner and its affiliates are not voted in favor of that removal:

 

   

the subordination period will end, and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

   

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

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our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

In the event of the removal of our general partner under circumstances where cause exists or withdrawal of our general partner where that withdrawal violates our partnership agreement, a successor general partner will have the option to purchase the general partner interest and incentive distribution rights of the departing general partner for a cash payment equal to the fair market value of those interests. Under all other circumstances where our general partner withdraws or is removed by the limited partners, the departing general partner will have the option to require the successor general partner to purchase the general partner interest of the departing general partner and its incentive distribution rights for fair market value. In each case, this fair market value will be determined by agreement between the departing general partner and the successor general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing general partner and the successor general partner will determine the fair market value. Or, if the departing general partner and the successor general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing general partner or the successor general partner, the departing general partner’s general partner interest and its incentive distribution rights will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, we will be required to reimburse the departing general partner for all amounts due the departing general partner, including, without limitation, all employee-related liabilities, including severance liabilities incurred as a result of the termination of any employees employed for our benefit by the departing general partner or its affiliates.

Transfer of General Partner Units

Except for transfer by our general partner of all, but not less than all, of its general partner units to:

 

   

an affiliate of our general partner (other than an individual); or

 

   

another entity as part of the merger or consolidation of our general partner with or into another entity or the transfer by our general partner of all or substantially all of its assets to another entity,

our general partner may not transfer all or any of its general partner units to another person prior to March 31, 2020 without the approval of the holders of at least a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. As a condition of this transfer, the transferee must assume, among other things, the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

Our general partner and its affiliates may, at any time, transfer common units or subordinated units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to us.

Transfer of Ownership Interests in the General Partner

At any time, Chesapeake and its affiliates may sell or transfer all or part of its ownership interests in our general partner to an affiliate or third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may transfer its incentive distribution rights to (i) an affiliate of the holder (other than an individual) or (ii) another entity as part of the merger or consolidation of such holder with or into another entity, the sale of all of the ownership interests in such holder or the sale of all or

 

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substantially all of such holder’s assets to that entity without the prior approval of the unitholders; provided that, in the case of the sale of ownership interests in such holder, the initial holder of the incentive distribution rights continues to remain the general partner following such sale. Prior to March 31, 2020, any other transfer of incentive distribution rights will require the affirmative vote of holders of a majority of the outstanding common units, excluding common units held by our general partner and its affiliates. On or after March 31, 2020, the incentive distribution rights will be freely transferable.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Chesapeake Midstream GP, L.L.C. as our general partner or from otherwise changing our management. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units directly from our general partner or its affiliates or any transferee of that person or group that is approved by our general partner or to any person or group who acquires the units with the prior approval of the board of directors of our general partner.

Our partnership agreement also provides that if our general partner is removed as our general partner under circumstances where cause does not exist and units held by our general partner and its affiliates are not voted in favor of that removal:

 

   

the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis;

 

   

any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished; and

 

   

our general partner will have the right to convert its general partner units and its incentive distribution rights into common units or to receive cash in exchange for those interests based on the fair market value of those interests at that time.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or to us, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons as of a record date to be selected by our general partner, on at least 10, but not more than 60, days notice. The purchase price in the event of this purchase is the greater of:

 

   

the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase those limited partner interests; and

 

   

the average of the daily closing prices of the partnership securities of such class over the 20 trading days preceding the date three days before the date the notice is mailed.

Our general partner may assign its limited call right to the affiliates.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have his limited partner interests purchased at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. Please read “Material Tax Consequences—Disposition of Common Units.”

 

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Ineligible Assignees; Redemption

Our general partner, acting on our behalf, may at any time require any or all unitholders to certify:

 

   

that the unitholder is a U.S. individual or an entity subject to U.S. federal income taxation on the income generated by us; or

 

   

that, if the unitholder is a U.S. entity not subject to U.S. federal income taxation on the income generated by us, as in the case, for example, of a mutual fund taxed as a regulated investment company or a partnership, all the entity’s owners are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us.

This certification can be changed in any manner our general partner determines is necessary or appropriate to implement its original purpose.

If a unitholder fails to furnish:

 

   

the required certification within 30 days after request; or

 

   

provides a false certification; then

we will have the right, which we may assign to any of our affiliates, to acquire all but not less than all of the units held by such unitholder. Further, our general partner may elect not to make distributions or allocate income or loss to such unitholder.

The purchase price in the event of such an acquisition for each unit held by such unitholder will be the lesser of:

 

  (i) the price paid by such unitholder for the relevant unit; and

 

  (ii) the average of the daily closing prices of the units for the prior 20 consecutive trading days.

The purchase price will be paid in cash or by delivery of a promissory note, as determined by our general partner. Any such promissory note will bear interest at the rate of 5% annually and be payable in three equal annual installments of principal and accrued interest, commencing one year after the redemption date.

Non-Citizen Assignees; Redemption

If we are or become subject to federal, state or local laws or regulations that, in the reasonable determination of our general partner, create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, we may redeem the units held by that limited partner at their current market price. In order to avoid any cancellation or forfeiture, our general partner may require each limited partner to furnish information about his nationality, citizenship or related status. If a limited partner fails to furnish information about his nationality, citizenship or other related status within 30 days of a request for the information or our general partner determines after receipt of the information that the limited partner is not an eligible citizen, the limited partner may be treated as a non-citizen assignee. A non-citizen assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. 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.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

 

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Our general partner does not anticipate that any meeting of our unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting, if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum, unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Securities.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise. Except as our partnership agreement otherwise provides, subordinated units will vote together with common units, as a single class.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

   

our general partner;

 

   

any departing general partner;

 

   

any person who is or was an affiliate of our general partner or any departing general partner;

 

   

any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

 

   

any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner, any departing general partner, an affiliate of our general partner or an affiliate of any departing general partners; and

 

   

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets

 

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to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner and its affiliates for all expenses they incurs or payments they make on our behalf. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. These books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 120 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those consolidated financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to our unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and in filing his federal and state income tax returns, regardless of whether he supplies us with the necessary information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable written demand stating the purpose of such demand and at his own expense, have furnished to him:

 

   

a current list of the name and last known address of each partner;

 

   

a copy of our tax returns;

 

   

information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each partner became a partner;

 

   

copies of our partnership agreement, our certificate of limited partnership and related amendments and powers of attorney under which they have been executed;

 

   

information regarding the status of our business and our financial condition; and

 

   

any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

 

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Registration Rights

Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units, subordinated units or other partnership securities proposed to be sold by our general partner or any of its affiliates or their assignees if an exemption from the registration requirements is not otherwise available. These registration rights continue for two years following any withdrawal or removal of Chesapeake Midstream GP, L.L.C. as our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and fees. Please read “Units Eligible for Future Sale.”

 

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UNITS ELIGIBLE FOR FUTURE SALE

After the sale of the common units offered hereby, Chesapeake and GIP will hold an aggregate of              common units and             subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and some may convert earlier. The sale of these units could have an adverse impact on the price of the common units or on any trading market that may develop.

The common units sold in the offering will generally be freely transferable without restriction or further registration under the Securities Act, except that any common units owned by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption under Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of the issuer to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

   

1.0% of the total number of the securities outstanding, or

 

   

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned his common units for at least six months (provided we are in compliance with the current public information requirement) or one year (regardless of whether we are in compliance with the current public information requirement), would be entitled to sell common units under Rule 144 without regard to the rule’s public information requirements, volume limitations, manner of sale provisions and notice requirements.

The partnership agreement does not restrict our ability to issue any partnership securities. Any issuance of additional common units or other equity securities would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the cash distributions to and market price of, our common units then outstanding. Please read “The Partnership Agreement—Issuance of Additional Securities.”

Under our partnership agreement, our general partner and its affiliates have the right to cause us to register under the Securities Act and state securities laws the offer and sale of any common units, subordinated units or other partnership securities that they hold. Subject to the terms and conditions of our partnership agreement, these registration rights allow our general partner and its affiliates or their assignees holding any units or other partnership securities to require registration of any of these units or other partnership securities and to include them in a registration by us of other units, including units offered by us or by any unitholder. Our general partner will continue to have these registration rights for two years following its withdrawal or removal as our general partner. In connection with any registration of this kind, we will indemnify each unitholder participating in the registration and its officers, directors and controlling persons from and against any liabilities under the Securities Act or any state securities laws arising from the registration statement or the prospectus. We will bear all costs and expenses incidental to any registration, excluding any underwriting discounts and fees. Except as described below, our general partner and its affiliates may sell their units or other partnership interests in private transactions at any time, subject to compliance with applicable laws.

Chesapeake, GIP, our partnership, our general partner and its affiliates, including the executive officers and directors of our general partner, and any participant who purchases over $100,000 worth of common units in our directed unit program have agreed not to sell any common units they beneficially own for a period of 180 days from the date of this prospectus. For a description of these lock-up provisions, please read “Underwriting.”

 

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MATERIAL TAX CONSEQUENCES

This section is a summary of the material tax considerations that may be relevant to prospective unitholders who are individual citizens or residents of the U.S. and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to legal conclusions with respect to matters of U.S. federal income tax law. This section is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Internal Revenue Code”), existing and proposed Treasury regulations promulgated under the Internal Revenue Code (the “Treasury Regulations”) and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Chesapeake Midstream Partners, L.P. and our operating company.

The following discussion does not comment on all federal income tax matters affecting us or our unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the U.S. and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we encourage each prospective unitholder to consult, and depend on, his own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to him of the ownership or disposition of common units.

No ruling has been or will be requested from the Internal Revenue Service (the “IRS”) regarding any matter affecting us or prospective unitholders. Instead, we will rely on opinions of Vinson & Elkins L.L.P. Unlike a ruling, an opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will result in a reduction in cash available for distribution to our unitholders and our general partner and thus will be borne indirectly by our unitholders and our general partner. Furthermore, the tax treatment of us, or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of the representations made by us.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following specific federal income tax issues: (i) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (ii) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please read “—Disposition of Common Units—Allocations Between Transferors and Transferees”); and (iii) whether our method for depreciating Section 743 adjustments is sustainable in certain cases (please read “—Tax Consequences of Unit Ownership—Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions by a partnership to a partner are generally not taxable to the partnership or the partner unless the amount of cash distributed to him is in excess of the partner’s adjusted basis in his partnership interest.

 

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Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the transportation, storage and processing of crude oil, natural gas and products thereof. Other types of qualifying income include interest (other than from a financial business), dividends, gains from the sale of real property and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than         % of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and our general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income. The portion of our income that is qualifying income may change from time to time.

No ruling has been or will be sought from the IRS and the IRS has made no determination as to our status or the status of our operating company for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Internal Revenue Code. Instead, we will rely on the opinion of Vinson & Elkins L.L.P. on such matters. It is the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, we will be classified as a partnership and our operating company will be disregarded as an entity separate from us for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied are:

 

   

Neither we nor the operating company has elected or will elect to be treated as a corporation; and

 

   

For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code; and

We believe that these representations have been true in the past and expect that these representations will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This deemed contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our tax return rather than being passed through to our unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

 

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The discussion below is based on Vinson & Elkins L.L.P.’s opinion that we will be classified as a partnership for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Chesapeake Midstream Partners, L.P. will be treated as partners of Chesapeake Midstream Partners, L.P. for federal income tax purposes. Also, unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units will be treated as partners of Chesapeake Midstream Partners, L.P. for federal income tax purposes.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “—Tax Consequences of Unit Ownership—Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore appear to be fully taxable as ordinary income. These holders are urged to consult their own tax advisors with respect to their tax consequences of holding common units in Chesapeake Midstream Partners, L.P. The references to “unitholders” in the discussion that follows are to persons who are treated as partners in Chesapeake Midstream Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-Through of Taxable Income . We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his share of our income, gains, losses and deductions without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year. Our taxable year ends on December 31.

Treatment of Distributions . Distributions by us to a unitholder generally will not be taxable to the unitholder for federal income tax purposes, except to the extent the amount of any such cash distribution exceeds his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “—Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution by us of cash to that unitholder. To the extent our distributions cause a unitholder’s “at-risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years. Please read “—Limitations on Deductibility of Losses.”

A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. This deemed distribution may constitute a non-pro rata distribution. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.” To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and then having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange will generally result in the unitholder’s realization of ordinary income, which will equal the excess of (i) the non-pro rata portion of that distribution over (ii) the unitholder’s tax basis (generally zero) for the share of Section 751 Assets deemed relinquished in the exchange.

 

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Ratio of Taxable Income to Distributions . We estimate that a purchaser of common units in this offering who owns those common units from the date of closing of this offering through the record date for distributions for the period ending December 31, 2012, will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be         % or less of the cash distributed with respect to that period. Thereafter, we anticipate that the ratio of allocable taxable income to cash distributions to the unitholders will increase. These estimates are based upon the assumption that gross income from operations will approximate the amount required to make the minimum quarterly distribution on all units and other assumptions with respect to capital expenditures, cash flow, net working capital and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and tax reporting positions that we will adopt and with which the IRS could disagree. Accordingly, we cannot assure you that these estimates will prove to be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units. For example, the ratio of allocable taxable income to cash distributions to a purchaser of common units in this offering will be greater, and perhaps substantially greater, than our estimate with respect to the period described above if:

 

   

gross income from operations exceeds the amount required to make minimum quarterly distributions on all units, yet we only distribute the minimum quarterly distributions on all units; or

 

   

we make a future offering of common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions during the period described above, such as to repay indebtedness outstanding at the time of this offering or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate applicable to our assets at the time of this offering.

Basis of Common Units . A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A unitholder will have no share of our debt that is recourse to our general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Limitations on Deductibility of Losses . The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder, estate, trust, or corporate unitholder (if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by or for five or fewer individuals or some tax-exempt organizations) to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A common unitholder subject to these limitations must recapture losses deducted in previous years to the extent that distributions cause his at-risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction to the extent that his at-risk amount is subsequently increased, provided such losses do not exceed such common unitholders’ tax basis in his common units. Upon the taxable disposition of a unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at-risk limitation but may not be offset by losses suspended by the basis limitation. Any loss previously suspended by the at-risk limitation in excess of that gain would no longer be utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by (i) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or other similar arrangement and (ii) any amount of money he borrows to acquire or hold his units, if the lender of those

 

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borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at-risk amount will increase or decrease as the tax basis of the unitholder’s units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

In addition to the basis and at-risk limitations on the deductibility of losses, the passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally trade or business activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or a unitholder’s investments in other publicly traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a fully taxable transaction with an unrelated party. The passive loss limitations are applied after other applicable limitations on deductions, including the at-risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any of our suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly traded partnerships.

Limitations on Interest Deductions . The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

   

interest on indebtedness properly allocable to property held for investment;

 

   

our interest expense attributed to portfolio income; and

 

   

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment or qualified dividend income. The IRS has indicated that the net passive income earned by a publicly traded partnership will be treated as investment income to its unitholders. In addition, the unitholder’s share of our portfolio income will be treated as investment income.

Entity-Level Collections . If we are required or elect under applicable law to pay any federal, state, local or foreign income tax on behalf of any unitholder or our general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the unitholder on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual unitholder in which event the unitholder would be required to file a claim in order to obtain a credit or refund.

 

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Allocation of Income, Gain, Loss and Deduction . In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our general partner and the unitholders in accordance with their percentage interests in us. At any time that distributions are made to the common units in excess of distributions to the subordinated units, or incentive distributions are made to our general partner, gross income will be allocated to the recipients to the extent of these distributions. If we have a net loss, that loss will be allocated first to our general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to our general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for (i) any difference between the tax basis and fair market value of our assets at the time of an offering and (ii) any difference between the tax basis and fair market value of any property contributed to us by the general partner and its affiliates that exists at the time of such contribution, together, referred to in this discussion as the “Contributed Property.” The effect of these allocations, referred to as Section 704(c) Allocations, to a unitholder purchasing common units from us in this offering will be essentially the same as if the tax bases of our assets were equal to their fair market values at the time of this offering. In the event we issue additional common units or engage in certain other transactions in the future, “reverse Section 704(c) Allocations,” similar to the Section 704(c) Allocations described above, will be made to the general partner and our other unitholders immediately prior to such issuance or other transactions to account for the difference between the “book” basis for purposes of maintaining capital accounts and the fair market value of all property held by us at the time of such issuance or future transaction. In addition, items of recapture income will be allocated to the extent possible to the unitholder who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner sufficient to eliminate the negative balance as quickly as possible.

An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including:

 

   

his relative contributions to us;

 

   

the interests of all the partners in profits and losses;

 

   

the interest of all the partners in cash flow; and

 

   

the rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Common Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales . 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, he 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. As a result, during this period:

 

   

any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

 

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any cash distributions received by the unitholder as to those units would be fully taxable; and

 

   

all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units; therefore, 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 and loaning their units. The IRS has previously announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please also read “—Disposition of Common Units—Recognition of Gain or Loss.”

Alternative Minimum Tax . Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates . Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 35% and the highest marginal U.S. federal income tax rate applicable to long-term capital gains (generally, capital gains on certain assets held for more than twelve months) of individuals is 15%. However, absent new legislation extending the current rates, beginning January 1, 2011, the highest marginal U.S. federal income tax rate applicable to ordinary income and long-term capital gains of individuals will increase to 39.6% and 20%, respectively. Moreover, these rates are subject to change by new legislation at any time.

Section 754 Election . We will make the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other unitholders. For purposes of this discussion, a unitholder’s inside basis in our assets will be considered to have two components: (i) his share of our tax basis in our assets (“common basis”) and (ii) his Section 743(b) adjustment to that basis.

We will adopt the remedial allocation method as to all our properties. Where the remedial allocation method is adopted, the Treasury Regulations under Section 743 of the Internal Revenue Code require a portion of the Section 743(b) adjustment that is attributable to recovery property subject to depreciation under Section 168 of the Internal Revenue Code whose book basis is in excess of its tax basis to be depreciated over the remaining cost recovery period for the property’s unamortized Book-Tax Disparity. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code, rather than cost recovery deductions under Section 168, is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, our general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these and any other Treasury Regulations. Please read “—Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no direct or indirect controlling authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as non-amortizable to the extent attributable to property which is not amortizable. This method is consistent with the methods employed by other publicly traded partnerships but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our

 

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assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “—Uniformity of Units.” A unitholder’s tax basis for his common units is reduced by his share of our deductions (whether or not such deductions were claimed on an individual’s income tax return) so that any position we take that understates deductions will overstate the common unitholder’s basis in his common units, which may cause the unitholder to understate gain or overstate loss on any sale of such units. Please read “—Disposition of Common Units—Recognition of Gain or Loss.” The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of the units. If such a challenge were sustained, the gain from the sale of units might be increased without the benefit of additional deductions.

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation deductions and his share of any gain or loss on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election. A basis adjustment is required regardless of whether a Section 754 election is made in the case of a transfer of an interest in us if we have a substantial built–in loss immediately after the transfer, or if we distribute property and have a substantial basis reduction. Generally a built–in loss or a basis reduction is substantial if it exceeds $250,000.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment allocated by us to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year . We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of his units following the close of our taxable year but before the close of his taxable year must include his share of our income, gain, loss and deduction in income for his taxable year, with the result that he will be required to include in income for his taxable year his share of more than twelve months of our income, gain, loss and deduction. Please read “—Disposition of Common Units—Allocations Between Transferors and Transferees.”

Initial Tax Basis, Depreciation and Amortization . The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets

 

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and their tax basis immediately prior to (i) this offering will be borne by our general partner and its affiliates, and (ii) any other offering will be borne by our general partner and other unitholders as of that time. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets subject to these allowances are placed in service. Please read “—Uniformity of Units.” Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Common Units—Recognition of Gain or Loss.”

The costs we incur in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties . The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss . Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property received by him plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held for more than twelve months will generally be taxed at a maximum U.S. federal income tax rate of 15% through December 31, 2010 and 20% thereafter (absent new legislation extending or adjusting the current rate). However, a portion of this gain or loss, which will likely be substantial, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized receivables” or to “inventory

 

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items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital losses may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gains in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in his entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership. Treasury Regulations under Section 1223 of the Internal Revenue Code allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling discussed above, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, he may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions is urged to consult his tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

   

a short sale;

 

   

an offsetting notional principal contract; or

 

   

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees . In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month, which we refer to in this prospectus as the “Allocation Date.” However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Internal Revenue Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, the Department of the Treasury and the IRS issued proposed Treasury

 

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Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferor and transferee unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferor and transferee unitholders, as well as unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements . A unitholder who sells any of his units is generally required to notify us in writing of that sale within 30 days after the sale (or, if earlier, January 15 of the year following the sale). A purchaser of units who purchases units from another unitholder is also generally required to notify us in writing of that purchase within 30 days after the purchase. Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a purchase may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the U.S. and who effects the sale or exchange through a broker who will satisfy such requirements.

Constructive Termination . We will be considered to have been terminated for tax purposes if there are sales or exchanges which, in the aggregate, constitute 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of measuring whether the 50% threshold is reached, multiple sales of the same interest are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A constructive termination occurring on a date other than December 31 will result in us filing two tax returns (and unitholders may receive two Schedules K-1) for one fiscal year and the cost of the preparation of these returns will be borne by all common unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination. The IRS has announced recently that it plans to issue guidance regarding the treatment of constructive terminations of publicly traded partnerships such as us. Any such guidance may change the application of the rules discussed above and may affect the tax treatment of a unitholder.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of

 

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depreciation or amortization derived from the depreciation or amortization method and useful life applied to the property’s unamortized Book-Tax Disparity, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743 of the Internal Revenue Code, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. Please read “—Tax Consequences of Unit Ownership—Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury Regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable methods and lives as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased without the benefit of additional deductions. Please read “—Disposition of Common Units—Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations and other foreign persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder that is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the U.S. because of the ownership of units. As a consequence, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, we will withhold at the highest applicable effective tax rate from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a U.S. trade or business, that corporation may be subject to the U.S. branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a U.S. trade or business. That tax may be reduced or eliminated by an income tax treaty between the U.S. and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

 

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A foreign unitholder who sells or otherwise disposes of a common unit will be subject to U.S. federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign common unitholder generally will be subject to U.S. federal income tax upon the sale or disposition of a common unit if (i) he owned (directly or constructively applying certain attribution rules) more than 5% of our common units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the common units or the 5-year period ending on the date of disposition. Currently, more than 50% of our assets consist of U.S. real property interests and we do not expect that to change in the foreseeable future. Therefore, foreign unitholders may be subject to federal income tax on gain from the sale or disposition of their units.

Administrative Matters

Information Returns and Audit Procedures . We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, Treasury Regulations or administrative interpretations of the IRS. Neither we nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. Our partnership agreement names Chesapeake Midstream GP, L.L.C. as our Tax Matters Partner.

The Tax Matters Partner has made and will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

 

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Nominee Reporting . Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

   

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

   

whether the beneficial owner is:

 

   

a person that is not a U.S. person;

 

   

a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

   

a tax-exempt entity;

 

   

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

   

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Accuracy-Related Penalties . An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

   

for which there is, or was, “substantial authority”; or

 

   

as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the adjusted basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or adjusted basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Internal Revenue Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Internal Revenue Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts.

No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 200% or

 

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more than the correct valuation, the penalty imposed increases to 40%. We do not anticipate making any valuation misstatements.

Reportable Transactions . If we were to engage in a “reportable transaction,” we (and possibly you and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single year, or $4 million in any combination of 6 successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly your tax return) would be audited by the IRS. Please read “—Information Returns and Audit Procedures.”

Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, you may be subject to the following provisions of the American Jobs Creation Act of 2004:

 

   

accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

   

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

   

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local, Foreign and Other Tax Considerations

In addition to federal income taxes, you likely will be subject to other taxes, such as state, local and foreign income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. We will initially own property or do business in Arkansas, Kansas, New Mexico, Oklahoma and Texas. Each of these states, other than Texas, imposes a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. We may also own property or do business in other jurisdictions in the future. Although you may not be required to file a return and pay taxes in some jurisdictions because your income from that jurisdiction falls below the filing and payment requirement, you will be required to file income tax returns and to pay income taxes in many of these jurisdictions in which we do business or own property and may be subject to penalties for failure to comply with those requirements. In some jurisdictions, tax losses may not produce a tax benefit in the year incurred and may not be available to offset income in subsequent taxable years. Some of the jurisdictions may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the jurisdiction. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the jurisdiction, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld will be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “—Tax Consequences of Unit Ownership—Entity-Level Collections.” Based on current law and our estimate of our future operations, our general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent jurisdictions, of his investment in us. Accordingly, each prospective unitholder is urged to consult, and depend upon, his tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state, local and foreign, as well as U.S. federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local or foreign tax consequences of an investment in us.

 

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INVESTMENT IN CHESAPEAKE MIDSTREAM PARTNERS, L.P. BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and the restrictions imposed by Section 4975 of the Internal Revenue Code and provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of the Internal Revenue Code or ERISA (collectively, “Similar Laws”). For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or individual retirement accounts or annuities (“IRAs”) established or maintained by an employer or employee organization, and entities whose underlying assets are considered to include “plan assets” of such plans, accounts and arrangements. Among other things, consideration should be given to:

 

   

whether the investment is prudent under Section 404(a)(1)(B) of ERISA and any other applicable Similar Laws;

 

   

whether in making the investment, the plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA and any other applicable Similar Laws;

 

   

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return. Please read “Material Tax Consequences—Tax-Exempt Organizations and Other Investors;” and

 

   

whether making such an investment will comply with the delegation of control and prohibited transaction provisions of ERISA, the Internal Revenue Code and any other applicable Similar Laws.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code prohibit employee benefit plans, and IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets” with parties that, with respect to the plan, are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code unless an exemption is available. A party in interest or disqualified person who engages in a non-exempt prohibited transaction may be subject to excise taxes and other penalties and liabilities under ERISA and the Internal Revenue Code. In addition, the fiduciary of the ERISA plan that engaged in such a non-exempt prohibited transaction may be subject to penalties and liabilities under ERISA and the Internal Revenue Code.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner would also be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code, ERISA and any other applicable Similar Laws.

The Department of Labor regulations provide guidance with respect to whether, in certain circumstances, the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets.” Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

  (a) the equity interests acquired by the employee benefit plan are publicly offered securities— i.e. , the equity interests are widely held by 100 or more investors independent of the issuer and each other, are freely transferable and are registered under certain provisions of the federal securities laws;

 

  (b) the entity is an “operating company,”— i.e. , it is primarily engaged in the production or sale of a product or service, other than the investment of capital, either directly or through a majority-owned subsidiary or subsidiaries; or

 

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  (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above that are subject to ERISA and IRAs and other similar vehicles that are subject to Section 4975 of the Internal Revenue Code.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above.

In light of the serious penalties imposed on persons who engage in prohibited transactions or other violations, plan fiduciaries contemplating a purchase of common units should consult with their own counsel regarding the consequences under ERISA, the Internal Revenue Code and other Similar Laws.

 

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UNDERWRITING

Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are acting as joint book-running managers of this offering and as representatives of the underwriters named below. Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus, each underwriter named below has severally agreed to purchase, and we have agreed to sell to that underwriter, the number of common units set forth opposite the underwriter’s name.

 

Underwriter

   Number of
Common
Units

Citigroup Global Markets Inc.

  

Morgan Stanley & Co. Incorporated

  
    

Total

  
    

The underwriting agreement provides that the obligations of the underwriters to purchase the common units included in this offering are subject to approval of legal matters by counsel and to other conditions. The underwriters are obligated to purchase all the common units (other than those covered by the over-allotment option described below) if they purchase any of the common units.

Common units sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any common units sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price not to exceed $              per common unit. If all the common units are not sold at the initial offering price, the underwriters may change the offering price and the other selling terms.

If the underwriters sell more common units than the total number set forth in the table above, we have granted to the underwriters an option, exercisable for 30 days from the date of this prospectus, to purchase up to additional common units at the public offering price less the underwriting discount. The underwriters may exercise the option solely for the purpose of covering over-allotments, if any, in connection with this offering. To the extent the option is exercised, each underwriter must purchase a number of additional common units approximately proportionate to that underwriter’s initial purchase commitment. Any common units issued or sold under the option will be issued and sold on the same terms and conditions as the other common units that are the subject of this offering.

We, our general partner, certain of our general partner’s officers and directors, certain of our affiliates, including Chesapeake and GIP, and certain of their officers and directors have agreed that, for a period of 180 days from the date of this prospectus, we and they will not, without the prior written consent of Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated, offer, pledge, sell, contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant to purchase, lend or otherwise transfer or dispose of, directly or indirectly, any common units or any securities convertible into or exercisable or exchangeable for common units, or enter into any swap or other arrangement that transfers to another, in whole or in part, any of the economic consequences of ownership of the common units, whether any such transaction described above is to be settled by delivery of common units or such other securities, in cash or otherwise.

Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated, in their sole discretion, may release any of the securities subject to these lock-up agreements at any time without notice. Notwithstanding the foregoing, if (i) during the last 17 days of the 180-day restricted period, we issue an earnings release or material news or a material event relating to our company occurs or (ii) prior to the expiration of the 180-day restricted period, we announce that we will release earnings results during the 16-day period beginning on the last day of the 180-day

 

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restricted period, the restrictions described above shall continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the occurrence of the material news or material event.

Prior to this offering, there has been no public market for our common units. Consequently, the initial public offering price for the common units was determined by negotiations between us and the representatives. Among the factors considered in determining the initial public offering price were our results of operations, our current financial condition, our future prospects, our markets, the economic conditions in and future prospects for the industry in which we compete, our management, and currently prevailing general conditions in the equity securities markets, including current market valuations of publicly traded companies considered comparable to our company. We cannot assure you, however, that the price at which the common units will sell in the public market after this offering will not be lower than the initial public offering price or that an active trading market in our common units will develop and continue after this offering.

We intend to apply to list our common units on the NYSE under the symbol “CHM”. The underwriters have undertaken to sell common units to a minimum of 400 beneficial owners in lots of 100 or more common units to meet the NYSE distribution requirements for trading.

The following table shows the underwriting discounts and commissions that we are to pay to the underwriters in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ over-allotment option.

 

     Paid by Chesapeake
Midstream Partners
     No Exercise    Full Exercise

Per common unit

   $                 $             

Total

   $      $  

In connection with this offering, the underwriters may purchase and sell common units in the open market. Purchases and sales in the open market may include short sales, purchases to cover short positions, which may include purchases pursuant to the over-allotment option, and stabilizing purchases.

 

   

Short sales involve secondary market sales by the underwriters of a greater number of common units than they are required to purchase in this offering.

 

   

“Covered” short sales are sales of common units in an amount up to the number of common units represented by the underwriters’ over-allotment option.

 

   

“Naked” short sales are sales of common units in an amount in excess of the number of common units represented by the underwriters’ over-allotment option.

 

   

Covering transactions involve purchases of common units either pursuant to the over-allotment option or in the open market after the distribution has been completed in order to cover short positions.

 

   

To close a naked short position, the underwriters must purchase common units in the open market after the distribution has been completed. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in this offering.

 

   

To close a covered short position, the underwriters must purchase common units in the open market after the distribution has been completed or must exercise the over-allotment option. In determining the source of common units to close the covered short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option.

 

   

Stabilizing transactions involve bids to purchase common units so long as the stabilizing bids do not exceed a specified maximum.

 

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The underwriters also may impose a penalty bid. Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the underwriters, in covering short positions or making stabilizing purchases, repurchase common units originally sold by that syndicate member.

Purchases to cover short positions and stabilizing purchases, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of the common units. They may also cause the price of the common units to be higher than the price that would otherwise exist in the open market in the absence of these transactions. The underwriters may conduct these transactions on The New York Stock Exchange, in the over-the-counter market or otherwise. If the underwriters commence any of these transactions, they may discontinue them at any time.

A prospectus in electronic format may be made available on the web sites maintained by one or more of the underwriters. The representatives may agree to allocate a number of common units to underwriters for sale to their online brokerage account holders. The representatives will allocate common units to underwriters that may make Internet distributions on the same basis as other allocations. In addition, common units may be sold by the underwriters to securities dealers who resell common units to online brokerage account holders.

We estimate that our portion of the total expenses of this offering will be approximately $            .

At our request, certain of the underwriters have reserved up to              common units for sale at the initial public offering price to the officers, directors and employees of our general partner and its sole member and certain other persons associated with us. We do not know if these persons will choose to purchase all or any portion of these reserved units, but any purchases they do make will reduce the number of units available to the general public. Any reserved units not so purchased will be offered by the underwriters to the general public on the same basis as the other units offered by this prospectus. These persons must commit to purchase no later than before the open of business on the day following the date of this prospectus, but in any event these persons are not obligated to purchase common units and may not commit to purchase common units prior to the effectiveness of the registration statement relating to this offering.

The underwriters have performed commercial banking, investment banking and advisory services for us, Chesapeake and GIP and our respective affiliates from time to time for which they have received customary fees and reimbursement of expenses. The underwriters may, from time to time, engage in transactions with and perform services for us, Chesapeake and GIP and our respective affiliates, in the ordinary course of their business for which they may receive customary fees and reimbursement of expenses. Affiliates of Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are lenders under our secured credit facility and, in that respect, will receive a portion of the net proceeds from this offering. Affiliates of Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are counterparties to Chesapeake’s multi-counterparty secured hedging facility. An affiliate of Morgan Stanley & Co. Incorporated is the purchaser of a volumetric production payment from Chesapeake. An affiliate of Citigroup Global Markets, Inc. is a lender under GIP’s credit facility.

We and our general partner have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the underwriters may be required to make because of any of those liabilities.

Because the Financial Industry Regulatory Authority views our common units as interests in a direct participation program, this offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Notice to Prospective Investors in the European Economic Area

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), with effect from and including the date on which the Prospectus

 

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Directive is implemented in that relevant member state (the relevant implementation date), an offer of common units described in this prospectus may not be made to the public in that relevant member state prior to the publication of a prospectus in relation to the common units that has been approved by the competent authority in that relevant member state or, where appropriate, approved in another relevant member state and notified to the competent authority in that relevant member state, all in accordance with the Prospectus Directive, except that, with effect from and including the relevant implementation date, an offer of securities may be offered to the public in that relevant member state at any time:

 

   

to any legal entity that is authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

 

   

to any legal entity that has two or more of (i) an average of at least 250 employees during the last financial year; (ii) a total balance sheet of more than €43,000,000 and (iii) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;

 

   

to fewer than 100 natural or legal persons (other than qualified investors as defined below) subject to obtaining the prior consent of the representatives for any such offer; or

 

   

in any other circumstances that do not require the publication of a prospectus pursuant to Article 3 of the Prospectus Directive.

Each purchaser of common units described in this prospectus located within a relevant member state will be deemed to have represented, acknowledged and agreed that it is a “qualified investor” within the meaning of Article 2(1)(e) of the Prospectus Directive.

For purposes of this provision, the expression an “offer to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC and includes any relevant implementing measure in each relevant member state.

The sellers of the common units have not authorized and do not authorize the making of any offer of common units through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the common units as contemplated in this prospectus. Accordingly, no purchaser of the common units, other than the underwriters, is authorized to make any further offer of the common units on behalf of the sellers or the underwriters.

Notice to Prospective Investors in the United Kingdom

This prospectus is only being distributed to, and is only directed at, persons in the United Kingdom that are qualified investors within the meaning of Article 2(1)(e) of the Prospectus Directive that are also (i) investment professionals falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 (the “Order”) or (ii) high net worth entities, and other persons to whom it may lawfully be communicated, falling within Article 49(2)(a) to (d) of the Order (each such person being referred to as a “relevant person”). This prospectus and its contents are confidential and should not be distributed, published or reproduced (in whole or in part) or disclosed by recipients to any other persons in the United Kingdom. Any person in the United Kingdom that is not a relevant person should not act or rely on this document or any of its contents.

Notice to Prospective Investors in France

Neither this prospectus nor any other offering material relating to the common units described in this prospectus has been submitted to the clearance procedures of the Autorité des Marchés Financiers or of the

 

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competent authority of another member state of the European Economic Area and notified to the Autorité des Marchés Financiers . The common units have not been offered or sold and will not be offered or sold, directly or indirectly, to the public in France. Neither this prospectus nor any other offering material relating to the common units has been or will be:

 

   

released, issued, distributed or caused to be released, issued or distributed to the public in France; or

 

   

used in connection with any offer for subscription or sale of the common units to the public in France.

Such offers, sales and distributions will be made in France only:

 

   

to qualified investors ( investisseurs qualifiés ) and/or to a restricted circle of investors ( cercle restreint d’investisseurs ), in each case investing for their own account, all as defined in, and in accordance with articles L.411-2, D.411-1, D.411-2, D.734-1, D.744-1, D.754-1 and D.764-1 of the French Code monétaire et financier ;

 

   

to investment services providers authorized to engage in portfolio management on behalf of third parties; or

 

   

in a transaction that, in accordance with article L.411-2-II-1°-or-2°-or 3° of the French Code monétaire et financier and article 211-2 of the General Regulations ( Règlement Général ) of the Autorité des Marchés Financiers, does not constitute a public offer ( appel public à l’épargne ).

The common units may be resold directly or indirectly, only in compliance with articles L.411-1, L.411-2, L.412-1 and L.621-8 through L.621-8-3 of the French Code monétaire et financier .

Notice to Prospective Investors in Hong Kong

The common units may not be offered or sold in Hong Kong by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong) and no advertisement, invitation or document relating to the common units may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to common units which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

Notice to Prospective Investors in Japan

The common units offered in this prospectus have not been registered under the Securities and Exchange Law of Japan. The common units have not been offered or sold and will not be offered or sold, directly or indirectly, in Japan or to or for the account of any resident of Japan, except (i) pursuant to an exemption from the registration requirements of the Securities and Exchange Law of Japan and (ii) in compliance with any other applicable requirements of Japanese law.

Notice to Prospective Investors in Singapore

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the common units may not be circulated or distributed, nor may the

 

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common units be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (i) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore (the “SFA”), (ii) to a relevant person pursuant to Section 275(1), or any person pursuant to Section 275(1A), and in accordance with the conditions specified in Section 275 of the SFA or (iii) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA, in each case subject to compliance with conditions set forth in the SFA.

Where the common units are subscribed or purchased under Section 275 of the SFA by a relevant person which is:

 

   

a corporation (which is not an accredited investor (as defined in Section 4A of the SFA)) the sole business of which is to hold investments and the entire common unit capital of which is owned by one or more individuals, each of whom is an accredited investor; or

 

   

a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary of the trust is an individual who is an accredited investor,

common units, debentures and units of common units and debentures of that corporation or the beneficiaries’ rights and interest (howsoever described) in that trust shall not be transferred within six months after that corporation or that trust has acquired the common units pursuant to an offer made under Section 275 of the SFA except:

 

   

to an institutional investor (for corporations, under Section 274 of the SFA) or to a relevant person defined in Section 275(2) of the SFA, or to any person pursuant to an offer that is made on terms that such common units, debentures and units of common units and debentures of that corporation or such rights and interest in that trust are acquired at a consideration of not less than S$200,000 (or its equivalent in a foreign currency) for each transaction, whether such amount is to be paid for in cash or by exchange of securities or other assets, and further for corporations, in accordance with the conditions specified in Section 275 of the SFA;

 

   

where no consideration is or will be given for the transfer; or

 

   

where the transfer is by operation of law.

 

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VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.

EXPERTS

The consolidated financial statements of Chesapeake Midstream Development, L.P. as of December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008 included in this prospectus have been so included in reliance on the report, which contains an explanatory paragraph relating to significant transactions with affiliated entities as described in the notes to the financial statements, of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The balance sheet of Chesapeake Midstream Partners, L.P. as of February 12, 2010 and the balance sheet of Chesapeake Midstream GP, L.L.C. as of February 12 , 2010 included in this prospectus have been so included in reliance on the reports of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-l regarding the common units. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common units offered by this prospectus, you may desire to review the full registration statement, including its exhibits and schedules, filed under the Securities Act. The registration statement of which this prospectus forms a part, including its exhibits and schedules, may be inspected and copied at the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of the materials may also be obtained from the SEC at prescribed rates by writing to the public reference room maintained by the SEC at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the public reference room by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site on the Internet at http://www.sec.gov. Our registration statement, of which this prospectus constitutes a part, can be downloaded from the SEC’s web site.

We intend to furnish our unitholders annual reports containing our audited consolidated financial statements and to furnish or make available to our unitholders quarterly reports containing our unaudited interim financial information for the first three fiscal quarters of each of our fiscal years.

FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus may contain forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. These forward-looking statements involve risks and uncertainties. When considering these forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus. The risk factors and other factors noted throughout this prospectus could cause our actual results to differ materially from those contained in any forward-looking statement.

 

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INDEX TO FINANCIAL STATEMENTS

 

CHESAPEAKE MIDSTREAM PARTNERS, L.P. UNAUDITED PRO FORMA FINANCIAL DATA:

Introduction

   F-2

Unaudited pro forma balance sheet as of September 30, 2009

   F-3

Unaudited pro forma statement of operations for the year ended December 31, 2008

   F-4

Unaudited pro forma statement of operations for the nine months ended September 30, 2009

   F-5

Notes to unaudited pro forma financial data

   F-6

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. CONSOLIDATED FINANCIAL STATEMENTS:

  

Consolidated balance sheets as of September 30, 2009 (unaudited) and December 31, 2008

   F-8

Unaudited Consolidated statements of operations for the nine months ended September  30, 2009 and 2008

   F-9

Unaudited Consolidated statements of cash flows for the nine months ended September  30, 2009 and 2008

   F-10

Unaudited Consolidated statements of changes in equity for the nine months ended September  30, 2009

   F-11

Notes to unaudited consolidated financial statements

   F-12

Report of independent registered public accounting firm

   F-17

Consolidated balance sheets as of December 31, 2008 and 2007

   F-18

Consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006

   F-19

Consolidated statements of changes in partners’ capital/division equity for the years ended December 31, 2008, 2007 and 2006

   F-20

Consolidated statements of cash flows for the years ended December 31, 2008, 2007 and 2006

   F-21

Notes to consolidated financial statements

   F-22

CHESAPEAKE MIDSTREAM PARTNERS, L.P. FINANCIAL STATEMENT:

  

Report of independent registered public accounting firm

   F-30

Balance sheet as of February 12, 2010

   F-31

Note to financial statement

   F-32

CHESAPEAKE MIDSTREAM GP, L.L.C. FINANCIAL STATEMENT:

  

Report of independent registered public accounting firm

   F-33

Balance sheet as of February 12, 2010

   F-34

Note to financial statement

   F-35


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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA FINANCIAL DATA

Introduction

The unaudited pro forma financial data of Chesapeake Midstream Partners, L.P. (the Partnership) as of September 30, 2009, for the year ended December 31, 2008 and the nine month period ended September 30, 2009, have been derived from the audited consolidated historical and unaudited consolidated interim financial statements of Chesapeake Midstream Development, L.P. and its subsidiaries (Chesapeake Midstream Development or our Predecessor) set forth elsewhere in this Prospectus and are qualified in their entirety by reference to such historical financial statements and related notes contained therein. In connection with this offering, a portion of the business of our Predecessor, consisting of certain assets and operations that have historically been principally engaged in gathering, compressing and treating natural gas for subsidiaries of Chesapeake Energy Corporation and other natural gas producers, will be contributed to the Partnership. This contribution will be recorded at historical cost. The historical financial statements included elsewhere in this prospectus reflect the assets, liabilities and operations of our Predecessor. Since the Partnership’s operations will only represent a portion of the operations of our Predecessor and due to other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting the Comparability of Our Financial Results,” the Partnership’s future results of operations will not be comparable to our Predecessor’s historical results. The unaudited pro forma financial data have been prepared on the basis that the Partnership will be treated as a partnership for federal income tax purposes. The unaudited pro forma financial data should be read in conjunction with the notes accompanying such unaudited pro forma financial data and with the audited consolidated historical and unaudited consolidated interim financial statements of Chesapeake Midstream Development and related notes set forth elsewhere in this Prospectus.

The unaudited pro forma balance sheet and the unaudited pro forma statements of operations were derived by adjusting the audited consolidated historical and unaudited consolidated interim financial statements of Chesapeake Midstream Development. The adjustments are based on currently available information and certain estimates and assumptions; therefore, actual adjustments will differ from the pro forma adjustments. However, management believes that the assumptions provide a reasonable basis for presenting the significant effects of the transactions as contemplated and that the pro forma adjustments give appropriate effect to those assumptions and are properly applied in the unaudited pro forma financial data.

The unaudited pro forma financial data are not necessarily indicative of the results that actually would have occurred if the Partnership had assumed operations of Chesapeake Midstream Development on the dates indicated, nor are they indicative of future results.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA BALANCE SHEET

September 30, 2009

 

    Predecessor
Historical
  Predecessor
Retained
Operations(a)
    Partnership
Pro Forma
  Adjustments
for the
Offering
    Partnership
Pro Forma
as Adjusted
    (In thousands)

Assets

         

Current assets:

         

Cash and cash equivalents

  $ 156,047   $ (156,012   $ 35   $ 300,000 (b)     $ 265,862
    —       —          —       (19,500 ) (c)       —  
    —       —          —       (2,500 ) (d)       —  
    —       —          —       (12,173 ) (e)       —  

Accounts receivable

    182,463     (87,484     94,979     —          94,979

Other current assets

    2,278     (672     1,606     —          1,606
                                 

Total current assets

    340,788     (244,168     96,620     265,827        362,447
                                 

Property, plant and equipment, net

    2,870,547     (1,125,574     1,744,973     —          1,744,973

Other assets

    21,505     (5,777     15,728     —          15,728
                                 

Total assets

  $ 3,232,840   $ (1,375,519   $ 1,857,321   $ 265,827      $ 2,123,148
                                 

Liabilities and Equity

         

Current liabilities:

         

Accounts payable

  $ 151,769   $ (108,012   $ 43,757   $ —        $ 43,757

Accrued liabilities and other

    33,649     23,857        57,506     —          57,506
                                 

Total current liabilities

    185,418     (84,155     101,263     —          101,263
                                 

Long-term liabilities:

         

Revolving credit facility

    12,173     —          12,173     (12,173 ) (e)       —  

Other liabilities

    2,699     —          2,699     —          2,699

Deferred income tax liabilities

    36,147     (36,147     —       —          —  
                                 

Total long-term liabilities

    51,019     (36,147     14,872     (12,173     2,699
                                 

Commitments and contingencies

         

Equity:

         

Partners’ capital

    2,125,810     (384,624     1,741,186     300,000 (b)       2,019,186
    —       —          —       (19,500 ) (c)       —  
    —       —          —       (2,500 ) (d)       —  

Common unitholders public, units issued and outstanding

    —       —          —       —          —  

Common unitholders—parent,             units issued and outstanding

    —       —          —       —          —  

Subordinated unitholders—parent,             issued and outstanding

    —       —          —       —          —  

General partner interest,             units issued and outstanding

    —       —          —       —          —  

Noncontrolling interest

    870,593     (870,593     —       —          —  
                                 

Total equity

    2,996,403     (1,255,217     1,741,186     278,000        2,019,186
                                 

Total liabilities and equity

  $ 3,232,840   $ (1,375,519   $ 1,857,321   $ 265,827      $ 2,123,148
                                 

See accompanying notes to unaudited pro forma financial data.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

Year Ended December 31, 2008

 

    Predecessor
Historical
    Predecessor
Retained
Operations(a)
    Partnership
Pro Forma
    Adjustments
for the
Offering
    Partnership
Pro Forma
as Adjusted
 
    (In thousands, except unit and per unit data)  

Revenues

  $ 332,783      $ (52,511   $ 280,272      $ —        $ 280,272   

Expenses:

         

Operating expenses (benefit)

    141,803        (23,943     117,860        —          117,860   

Depreciation and amortization expense (benefit)

    47,558        (8,008     39,550        —          39,550   

General and administrative expense (benefit)

    13,362        (2,302     11,060        2,000 (h)       13,060   

Interest expense (benefit)

    1,871        —          1,871        (1,871 ) (f)       411   
    —          —          —          411 (g)       —     

Impairment of property, plant and equipment and other assets

    30,000        —          30,000        —          30,000   
                                       

Total expenses

    234,594        (34,253     200,341        540        200,881   
                                       

(Gain) loss on sale of assets

    (5,541     5,541        —          —          —     

Other expense (income)

    (278     278        —          —          —     
                                       

Income before income tax expense (benefit)

    104,008        (24,077     79,931        (540     79,391   

Income tax expense (benefit)

    (61,287     (7,064     (68,351     —          (68,351
                                       

Net income (loss)

  $ 165,295      $ (17,013   $ 148,282      $ (540   $ 147,742   
                                       

General partner interest in net income

            —     

Common unitholders’ interest in net income

            —     

Subordinated unitholders’ interest in net income

            —     

Net income per common unit (basic and diluted)

            —     

Net income per subordinated unit (basic and diluted)

            —     

Weighted average number of limited partners’ units outstanding

         

Common units

         
               

Subordinated units

         
               

 

See accompanying notes to unaudited pro forma financial data.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

Nine Months Ended September 30, 2009

 

    Predecessor
Historical
    Predecessor
Retained
Operations(a)
    Partnership
Pro Forma
  Adjustments
for the
Offering
    Partnership
Pro Forma
as Adjusted
    (In thousands, except unit and per unit data)

Revenues

  $ 358,921      $ (83,203   $ 275,718   $ —        $ 275,718

Expenses:

         

Operating expenses (benefit)

    146,604        (36,430     110,174     —          110,174

Depreciation and amortization expense (benefit)

    65,477        (12,964     52,513     —          52,513

General and administrative expense (benefit)

    22,782        (7,502     15,280     1,500 (h)       16,780

Interest expense (benefit)

    347        (126     221     (221 ) (f)       1,162
    —          —          —       1,162 (g)       —  

Impairment of property, plant and equipment and other assets

    90,207        —          90,207     —          90,207
                                   

Total expenses (benefit)

    325,417        (57,022     268,395     2,441        270,836
                                   

(Gain) loss on sale of assets

    44,566        (44,553     13     —          13

Other expense (income)

    (29     54        25     —          25
                                   

Income before income tax expense (benefit)

    (11,033     (18,318     7,285     (2,441     4,844

Income tax expense (benefit)

    6,341        (6,341     —       —          —  
                                   

Net income (loss)

  $ (17,374   $ 24,659      $ 7,285   $ (2,441   $ 4,844
                                   

General partner interest in net income

            —  

Common unitholders’ interest in net income

            —  

Subordinated unitholders’ interest in net income

            —  

Net income per common unit (basic and diluted)

            —  

Net income per subordinated unit (basic and diluted)

            —  

Weighted average number of limited partners’ units outstanding

         

Common units

         
             

Subordinated units

         
             

 

See accompanying notes to unaudited pro forma financial data.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA FINANCIAL DATA

 

1. Basis of Presentation, Transactions and the Offering

The historical financial information is derived from the audited consolidated historical and unaudited consolidated interim financial statements of Chesapeake Midstream Development, L.P. and its subsidiaries (Chesapeake Midstream Development or our Predecessor). In connection with this offering, a portion of the business of our Predecessor, consisting of certain assets and operations that have historically been principally engaged in gathering, compressing and treating natural gas for subsidiaries of Chesapeake Energy Corporation and other natural gas producers, will be contributed to Chesapeake Midstream Partners, L.P. (the Partnership). This contribution will be recorded at historical cost. The historical financial information reflects the assets, liabilities and operations of our Predecessor. Since the Partnership’s operations will only represent a portion of the operations of our Predecessor and due to other factors described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Items Impacting the Comparability of Our Financial Results,” the Partnership’s future results of operations will not be comparable to our Predecessor’s historical results. The pro forma adjustments have been prepared as if the offering and transactions described in this prospectus had taken place on September 30, 2009, in the case of the pro forma balance sheet, and as of January 1, 2008, in the case of the pro forma statements of operations for the year ended December 31, 2008, and for the nine months ended September 30, 2009. The pro forma as adjusted financial data also do not give effect to our 20-year gas gathering agreements with Chesapeake or Total or any of the transaction documents that were originally entered into on September 30, 2009 in connection with the formation of the joint venture between Chesapeake and GIP.

 

2. Pro Forma Adjustments and Assumptions

The adjustments are based on currently available information and certain estimates and assumptions and therefore the actual effects of these transactions will differ from the pro forma adjustments. A general description of these transactions and adjustments is provided as follows:

 

  (a) The elimination of the assets and liabilities to be retained by our Predecessor together with their associated historical results of operations to include the impact of intercompany activity;

 

  (b) the gross proceeds of $300 million from the issuance and sale of              common units at an initial public offering price of $             per unit. If the underwriters were to exercise their option to purchase additional common units in full, gross proceeds to the Partnership would equal $345 million.

 

  (c) the payment of estimated underwriting discounts and commissions and structuring fees;

 

  (d) the payment of offering expenses;

 

  (e) the use of proceeds to pay down outstanding borrowings under the Partnership’s revolving credit facility;

 

  (f) the elimination of historical interest expense in connection with the use of proceeds from this offering to reduce the amount drawn on the Partnership’s revolving credit facility;

 

  (g) the additional commitment fees on the Partnership’s revolving credit facility following the pay down of amounts outstanding under the credit facility with the proceeds of this offering; and

 

  (h) the incurrence of incremental general and administrative expense of approximately $2 million per year that the Partnership anticipates as a result of being a publicly traded partnership, including expenses associated with annual and quarterly reporting, tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the New York Stock Exchange; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation.

 

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3. Pro Forma Net Income (Loss) per Unit

Pro forma net income (loss) per unit is determined by dividing the pro forma net income (loss) that would have been allocated, in accordance with the net income and loss allocation provisions of the limited partnership agreement, to the common and subordinated unitholders under the two-class method, after deducting the general partner’s interest of 2% in the pro forma net income (loss), by the number of common and subordinated units expected to be outstanding at the closing of the offering. For purposes of this calculation, we assumed that (1) the initial quarterly distribution was made to all unitholders for each quarter during the periods presented and (2) the number of units outstanding were              common units and              subordinated units. The common and subordinated unitholders represent 98% limited partner interests. All units were assumed to have been outstanding since January 1, 2008. Basic and diluted pro forma net income (loss) per unit are equivalent as there are no dilutive units at the date of closing of the initial public offering of the common units of Chesapeake Midstream Partners, L.P. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the general partner is entitled to receive certain incentive distributions that will result in more net income proportionately being allocated to the general partner than to the holders of common and subordinated units. The pro forma net income (loss) per unit calculations assume that no incentive distributions were made to the general partner because no such distribution would have been paid based upon the pro forma available cash from operating surplus for the period.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED BALANCE SHEETS

 

     As of
September 30,
2009
    As of
December 31,
2008
 
     (Unaudited)        
     (In thousands)  

Assets

    

Current assets:

    

Cash and cash equivalents

   $ 156,047      $ 82,025   

Accounts receivable, including $168,864 and $150,616 from related parties at September 30, 2009 and December 31, 2008, respectively

     182,463        151,909   

Other current assets

     2,278        377   
                

Total current assets

     340,788        234,311   
                

Property, plant and equipment:

    

Gathering systems

     3,101,727        2,450,298   

Other fixed assets

     48,060        15,924   
                
     3,149,787        2,466,222   

Less: Accumulated depreciation

     (279,240     (126,749
                

Total property, plant and equipment, net

     2,870,547        2,339,473   
                

Long-term assets:

    

Deferred loan costs, net

     21,505        9,981   
                

Total assets

   $ 3,232,840      $ 2,583,765   
                

Liabilities and Equity

    

Current liabilities:

    

Accounts payable, including $24,508 and $41,239 due to related parties at September 30, 2009 and December 31, 2008, respectively

   $ 151,769      $ 286,400   

Accrued liabilities

     33,649        8,643   
                

Total current liabilities

     185,418        295,043   
                

Long-term liabilities:

    

Deferred income tax liabilities

     36,147        29,806   

Revolving bank credit facility

     12,173        460,000   

Other liabilities

     2,699        5,647   
                

Total long-term liabilities

     51,019        495,453   
                

Commitments and contingencies (Note 5):

    

Partners’ capital:

    

General partner (2.0% interest)

     42,516        35,865   

Limited partner (98.0% interest)

     2,083,294        1,757,404   
                

Total Partners’ capital

     2,125,810        1,793,269   
                

Noncontrolling interest

     870,593        —     
                

Total equity

     2,996,403        1,793,269   
                

Total liabilities and equity

   $ 3,232,840      $ 2,583,765   
                

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

     Nine Months Ended
September 30,
 
     2009     2008  
     (In thousands)  

Revenues

   $ 358,921      $ 234,678   

Expenses:

    

Operating expenses

     146,604        97,419   

Depreciation and amortization expense

     65,477        31,529   

General and administrative expense

     22,782        9,400   

Interest expense

     347        —     

Impairment of property, plant and equipment and other assets

     90,207        —     
                

Total expenses

     325,417        138,348   
                

Gain (loss) on of sale of assets

     (44,566     6,242   

Other income

     29        306   
                

Income (loss) before income tax expense

     (11,033     102,878   

Income tax expense (benefit)

     6,341        (62,986
                

Net income (loss)

   $ (17,374   $ 165,864   
                

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

     Nine Months Ended
September 30,
 
     2009     2008  
     (In thousands)  

Cash flows from operating activities:

    

Net income

   $ (17,374   $ 165,864   

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization

     65,477        31,529   

Deferred income taxes

     6,341        (62,986

Impairment of property, plant and equipment and other assets

     90,207        —     

(Gain) loss on sale of assets

     44,566        (6,242

Other non-cash items

     (282     (461

Changes in assets and liabilities, net of acquisitions:

    

(Increase) decrease in accounts receivable

     (29,553     (14,822

Increase (decrease) in other assets

     (1,901     (360

Increase (decrease) in accounts payable

     (82,112     16,518   

Increase in accrued liabilities

     25,379        5,433   
                

Net cash provided by (used in) operating activities

     100,748        134,473   
                

Cash flows from investing activities:

    

Additions to property, plant and equipment

     (756,883     (885,395

Proceeds from sale of assets

     65,889        17,609   
                

Net cash used in investing activities

     (690,994     (867,786
                

Cash flows from financing activities:

    

Proceeds from long-term debt borrowings

     796,173        —     

Payments on long-term debt borrowings

     (1,244,000     —     

Contributions from Parent

     541,545        733,748   

Proceeds from sale of noncontrolling interest

     587,500        —     

Offering costs of long-term debt

     (16,950     (432
                

Net cash provided by financing activities

     664,268        733,316   
                

Net increase in cash and cash equivalents

     74,022        3   

Cash and cash equivalents:

    

Beginning of period

     82,025        26   
                

End of period

   $ 156,047      $ 29   
                

Supplemental disclosure of non-cash investing:

    

Changes in accounts payable related to purchases of property, plant and equipment

   $ (52,521   $ 18,105   

Changes in other liabilities related to asset retirement obligations

   $ (2,893   $ 1,473   

Contributions of property, plant and equipment from Parent

   $ 91,462      $ —     

Supplemental disclosure of cash payments for interest

   $ 7,478      $ —     

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(UNAUDITED)

 

     General Partner
Interest
    Limited Partner
Interest
    Noncontrolling
Interest
    Total
Equity
 
     (In thousands)  

Balance at January 1, 2009

   $ 35,865      $ 1,757,404      $ —        $ 1,793,269   

Contributions from Parent

     13,186        646,105        —          659,291   

Net loss

     (347     (17,027     —          (17,374

Sale of noncontrolling interest in midstream joint venture

     —          —          587,500        587,500   

Noncontrolling interest offering cost

     (323     (15,807     —          (16,130

Distribution to noncontrolling interest owner

     —          —          (10,153     (10,153

Allocation of joint venture capital to Global Infrastructure Partners

     (5,865     (287,381     293,246        —     
                                

Balance at September 30, 2009

   $ 42,516      $ 2,083,294      $ 870,593      $ 2,996,403   
                                

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

 

1. Organization and Nature of Business and Principles of Consolidation

Organization

Chesapeake Midstream Development, L.P. (“CMD”) is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating operations of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly-owned subsidiary of Chesapeake Energy Corporation (“Parent” or “Chesapeake”) were contributed to CMD. CEMI is the limited partner in CMD with a 98% ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner in CMD with a 2% ownership interest. CMM is a wholly owned subsidiary of CEMI.

CMD’s operations are conducted through wholly owned subsidiaries: Bluestem Gas Services, L.L.C., Texas Midstream Gas Services, L.L.C., Arkansas Midstream Gas Services Corp., AMGS, LLC, Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Gas Services, L.L.C., Oklahoma Midstream Gas Services L.L.C., Appalachia Midstream Services L.L.C., Ponder Midstream Gas Services, L.L.C., Mid-America Midstream Gas Services, L.L.C. and Mockingbird Midstream Gas Services, L.L.C. These subsidiaries are held by Chesapeake Midstream Operating, L.L.C., which is a wholly owned subsidiary of CMD.

Nature of Business

CMD conducts its operations in Oklahoma, Texas, Louisiana, Arkansas, Kansas, New Mexico, Colorado, West Virginia and Pennsylvania. The underlying assets consist of approximately 2,900 miles of gathering pipeline, two CO 2 /H 2 S extraction facilities and eight small hydrocarbon dew point control facilities.

Basis of Presentation

The interim financial data as of September 30, 2009 and for the nine months ended September 30, 2009 and September 30, 2008 is unaudited; in the opinion of management, the interim data includes all adjustments, consisting only of normal recurring adjustments, necessary to a fair statement of the results for the interim periods.

 

2. Summary of Significant Accounting Policies

Property, Plant and Equipment

As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is recorded in the statements of operations. CMD recorded a $44.6 million loss on the sale of certain non-core non-strategic gathering systems during the nine months ended September 30, 2009 as well as a $6.2 million gain on the sale of certain gathering systems sold in conjunction with an upstream transaction effected by Chesapeake during the nine months ended September 30, 2008.

Income Taxes

Prior to February 2008, CMD filed consolidated federal income and state returns with Chesapeake as required by law. In February 2008, CMD and certain subsidiaries became pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow

 

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through to the owners and accordingly, do not result in a provision for income taxes in the financial statements. As such, CMD provided for the change in legal structure which occurred in 2008 by recording $63.0 million of income tax benefit for the nine months ended September 30, 2008. The income tax expense of $6.3 million for the nine months ended September 30, 2009 is related to CMD’s remaining taxable entity and is based on a 37.5% effective tax rate.

 

3. Joint Venture

On September 30, 2009, CMD formed a joint venture with Global Infrastructure Partners (GIP), a New York-based private equity fund, to own and operate natural gas midstream assets. As part of the transaction, CMD contributed certain natural gas gathering and processing assets to a new entity, Chesapeake Midstream Partners, L.L.C. (CMP), and GIP purchased a 50% interest in CMP. CMD retained the remaining 50% interest in CMP and received a $588 million cash distribution from CMP. The assets contributed to the joint venture were substantially all of CMD’s midstream assets in the Barnett Shale and certain of its midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. The financial results of CMP have been consolidated and GIP’s 50% ownership interest is reflected as a noncontrolling interest as of September 30, 2009.

CMP focuses on unregulated business activities in service to both Chesapeake and third-party natural gas producers and its revenues are generated almost entirely from fixed fee-based arrangements for gathering, compression, dehydration and treating services. CMP has entered into various agreements with Chesapeake, including a long-term gas gathering agreement at rates consistent with current market pricing. CMP operates the contributed assets. Certain Chesapeake employees will provide services to CMP through an employee secondment agreement. In return for certain cost reimbursements, CMP utilizes various support functions within Chesapeake, including accounting, human resources and information technology.

Subsidiaries of CMD continue to operate CMD’s midstream assets outside of the CMP joint venture. These include natural gas gathering assets in the Fayetteville Shale, Haynesville Shale, Marcellus Shale and other areas in the Appalachian Basin.

Concurrent with GIP’s funding of its interest in the joint venture, CMP closed a new $500 million secured revolving bank credit facility to partially fund capital expenditures associated with the building of additional natural gas gathering systems and for general corporate purposes. Additionally, CMD amended and restated the existing midstream lending agreement to reduce the total capacity from $460 million to $250 million, among other changes. This separate secured revolving bank credit facility supports CMD’s continuing midstream activities.

For the nine months ended September 30, 2009, CMD recorded an $86.2 million impairment of certain of the gathering systems contributed to CMP prior to the formation of the joint venture, and expensed $4 million of debt issuance costs associated with the amendment of CMD’s $460 million credit facility. The combined impairment of $90.2 million was included in impairment of property, plant and equipment and other assets on our consolidated statement of operations.

The $871 million noncontrolling interest included in CMD’s consolidated equity at September 30, 2009 represents GIP’s 50% interest in the net assets of CMP, which were recorded by CMP at CMD’s historical cost basis. This noncontrolling interest includes the net proceeds of $577 million GIP contributed in exchange for a 50% ownership interest in CMP plus $293 million of CMD equity allocated to GIP in order to properly reflect GIP’s 50% interest in the carrying value of CMP’s net assets.

 

4. Debt

On October 15, 2008, CMD entered into a Credit Facility Agreement with total commitments of $460 million. CMD utilized the facility to fund capital expenditures associated with building additional natural gas

 

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gathering and other systems and for general corporate purposes related to CMD’s operations. At December 31, 2008, this revolving credit facility had an outstanding balance of $460 million.

On September 30, 2009, CMD formed a joint venture with GIP to own and operate certain natural gas midstream assets. Concurrent with GIP’s funding of its interest in the joint venture, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture’s building of additional natural gas gathering systems and for general corporate purposes. At the same time, CMD amended and restated the existing revolving credit facility to reduce its capacity from $460 million to $250 million, among other changes. This separate secured revolving bank credit facility supports CMD’s continuing midstream activities. For the nine months ended September 30, 2009, in conjunction with the establishment of the new facility, CMD expensed $4 million of debt issuance costs associated with the amendment of the $460 million credit facility. As of September 30, 2009, the joint venture credit facility had an outstanding balance of approximately $12.173 million and no letters of credit and as of September 30, 2009, the CMD credit facility had no outstanding balance or letters of credit.

CMD Credit Facility

The CMD credit facility matures in September 2012. Borrowings under the CMD credit facility are secured by all of the assets of the wholly-owned subsidiaries (the restricted subsidiaries) of CMD, itself a wholly-owned subsidiary of Chesapeake, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which would be subject to a margin that varies from 2.00% to 2.75% per annum according to the most recent indebtedness to EBITDA ratio (as defined) or (ii) the LIBOR plus a margin that varies from 3.00% to 3.75% per annum according to the most recent indebtedness to EBITDA ratio (as defined). The unused portion of the facility is subject to a commitment fee of 0.50% per annum according to the most recent indebtedness to EBITDA ratio (as defined). Interest is payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals.

The CMD credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its restricted subsidiaries to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined) not to exceed 3.50 to 1, and an EBITDA (as defined) to interest expense coverage ratio of not less than 3.00 to 1. As defined by the credit facility agreement, our indebtedness to EBITDA ratio was 0.01 to 1 and our EBITDA to interest expense coverage ratio was 6.62 to 1 at September 30, 2009. If CMD or its restricted subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the CMD facility could be declared immediately due and payable. The CMD credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its restricted subsidiaries may have with an outstanding principal amount in excess of $15 million.

Joint Venture Credit Facility

The Joint Venture Credit Facility matures in September 2012. Borrowings under this credit facility will be secured by all of the assets of the companies organized under the Joint Venture, which is 50% owned by Chesapeake and 50% owned by our joint venture partner GIP, and bear interest at our option at either (i) the greater of the reference rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which would be subject to a margin that varies from 2.00% to 2.75% per annum according to the most recent consolidated leverage ratio (which is defined as the ratio of consolidated indebtedness on any day to consolidated EBITDA for the most recent four consecutive fiscal quarters for which financial statements are available) or (ii) the LIBOR plus a margin that varies from 3.00% to 3.75% per annum according to the most recent consolidated leverage ratio. The unused portion of the revolving credit facility will be subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest will be payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals.

 

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The Joint Venture Credit Facility agreement will require maintenance of a consolidated leverage ratio of not more than 3.50 to 1, and an interest coverage ratio (which is defined as the ratio of consolidated EBITDA for the most recent four consecutive four fiscal quarters to consolidated interest expense for such period) of not less than 3.00 to 1. As defined by the revolving credit facility at September 30, 2009, our consolidated leverage ratio was 0.09 to 1 and our interest coverage ratio was 17.49 to 1.

Additionally, our revolving credit facility contains various covenants and restrictive provisions which limit the ability of the Joint Venture to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the Joint Venture should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the Joint Venture facility could be declared immediately due and payable. The Joint Venture credit facility agreement also has cross default provisions that apply to any other indebtedness the Joint Venture may have with an outstanding principal amount in excess of $15 million.

Fair Value

Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Based on the borrowing rates currently available to CMD for debt with similar terms and maturities, the carrying value of CMD’s long-term debt approximates its fair value.

 

5. Transactions with Affiliates and Concentration of Credit Risk

In the normal course of business, CMD provides natural gas gathering, treating and compression services to Parent and its affiliates. Historically, a substantial majority of revenues have been derived from Parent, which includes volumes attributable to third-party interest owners that participate in Parents’ operated wells, and are charged under short term contracts at market sensitive rates. CEMI accounted for 98% and 99% of CMD’s revenues for the nine months ended September 30, 2009 and 2008, respectively.

Certain of CMD’s gathering assets held by CMP are subject to an agreement with a subsidiary of the Parent, which agreement provides CMP rights and obligations equivalent to a capital lease. Under the terms of the agreement, CMP has rights to the associated capital assets for as long as the assets are in operation. Specifically, CMP will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to this agreement, CMP receives revenues derived from operation of the gathering systems. At September 30, 2009, approximately $121.4 million ($115.7 million net of accumulated depreciation) of CMP’s gathering system assets are held under such agreement. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, CMP has no capital lease obligation liability associated with the assets held under this agreement as of September 30, 2009.

In addition, Parent and its affiliates provide certain services to CMD including legal, accounting, treasury, information technology and administration. The employees supporting CMD’s operations are employees of CEMI or the Parent. CMD’s financial statements include costs allocated to it by Parent and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Parent’s centralized general and administrative functions. Prior to the completion of the Credit Facility Agreement, costs allocated to CMD were based on identification of Parent’s resources which directly benefit CMD and its proportionate share of costs based on CMD’s estimated usage of shared resources and functions. Costs were allocated to CMD based on its proportionate share of Parent’s headcount, compensation expense or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that CMD’s management believes are reasonable;

 

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however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if CMD had been operated as a stand-alone entity. As part of the terms of the omnibus agreement, effective October 15, 2008, the overhead rate for CMD was $0.02 per mmbtu. Effective July 1, 2009, the cap was raised to $0.03 per Mcf.

The accompanying financial statements include allocated charges from CEMI to cover payroll and benefits for CEMI employees directly involved in gathering and treating operations. Operating expenses allocated by CEMI were $3.5 million and $24.6 million for the nine months ended September 30, 2009, and 2008, respectively.

The accompanying financial statements include allocated charges from Parent for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. General and administrative charges allocated by Parent were $14.6 million and $7.1 million for the nine months ended September 30, 2009 and 2008, respectively. Management believes that the allocated general and administrative expense is representative of the costs and expenses incurred by Parent for CMD.

 

6. Commitments and Contingencies

On September 30, 2009, we entered into an agreement with MidCon Compression (“MidCon”) to rent compressors for ten years for aggregate lease payments of approximately $44 million annually. For seven years, CMP will only rent compressors from MidCon in the Barnett Shale and Mid-Continent acreage dedications. As of September 30, 2009, the minimum aggregate future lease payments were approximately $133 million.

 

7. Recently Issued Accounting Standards

Upon the adoption of accounting standards for variable interest entities on January 1, 2010, CMD will deconsolidate the joint venture with GIP and account for the investment in the joint venture under the equity method going forward. Adoption of this guidance will result in a cumulative effect adjustment for the difference in CMD’s equity in CMP at January 1, 2010, which was originally recorded at carry over basis, and what the fair value of CMD’s equity would have been at the formation of the joint venture based on the then fair value. This cumulative effect adjustment will create a basis difference between CMD’s equity investment balance and the underlying equity in the net assets of the joint venture. This difference will be accreted through earnings over the expected useful life of the underlying assets held by the partnership.

 

8. Subsequent Events

On January 25, 2010, Chesapeake closed an upstream joint venture arrangement with Total E&P USA, Inc. (“Total”) pursuant to which Total acquired a 25% non-operated interest in Chesapeake’s Barnett Shale acreage. In connection with the closing of the joint venture, Chesapeake Midstream Partners, L.P. entered into a 20-year gas gathering agreement with Total on substantially similar terms to the gas gathering agreement with Chesapeake. Under this agreement, Total will provide, among other things, 10-year volume commitments within the Barnett Shale region equal to approximately 25% of Chesapeake’s committed volumes in the Barnett Shale region. Any material subsequent events have been considered for disclosure through February 12, 2010.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the partners of Chesapeake Midstream Development, L.P.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of changes in partners’ capital/division equity, and of cash flows present fairly, in all material respects, the financial position of Chesapeake Midstream Development, L.P. and its subsidiaries (“CMD”) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. These consolidated financial statements are the responsibility of CMD’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits of these consolidated statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in the accompanying consolidated financial statements and footnotes, CMD earned substantially all of its revenues and has other significant transactions with affiliated entities.

/s/    PricewaterhouseCoopers LLP

Tulsa, Oklahoma

April 6, 2009

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED BALANCE SHEETS

DECEMBER 31, 2008 AND 2007

 

     As of December 31,  
     2008     2007  
     (In thousands)  

Assets

    

Current assets

    

Cash and cash equivalents

   $ 82,025      $ 26   

Accounts receivable, including $150,616 and $42,598 from related parties at December 31, 2008 and 2007, respectively

     151,909        44,046   

Other current assets

     377        239   
                

Total current assets

     234,311        44,311   
                

Property, plant and equipment

    

Gathering systems

     2,450,298        1,008,127   

Other fixed assets

     15,924        6,141   
                
     2,466,222        1,014,268   

Less: Accumulated depreciation

     (126,749     (48,467
                

Total property, plant and equipment, net

     2,339,473        965,801   
                

Long-term assets

    

Deferred loan costs, net

     9,981        —     
                

Total assets

   $ 2,583,765      $ 1,010,112   
                

Liabilities and Partners’ Capital/Division Equity

    

Current liabilities

    

Accounts payable, including $41,239 and $0 due to related parties at December 31, 2008 and 2007, respectively

   $ 286,400      $ 89,083   

Accrued liabilities

     8,643        2,566   
                

Total current liabilities

     295,043        91,649   
                

Long-term liabilities

    

Deferred income taxes

     29,806        66,579   

Revolving bank credit facility

     460,000        —     

Other liabilities

     5,647        4,463   
                

Total long-term liabilities

     495,453        71,042   
                

Commitments and contingencies (Notes 9 and 10)

    

Partners’ capital/division equity

    

Division equity

     —          847,421   

Partners’ capital

    

General partner (2.0% interest)

     35,865        —     

Limited partner (98.0% interest)

     1,757,404        —     
                

Total Partners’ capital/division equity

     1,793,269        847,421   
                

Total liabilties and Partners’ capital/division equity

   $ 2,583,765      $ 1,010,112   
                

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

 

     Year Ended December 31,
     2008     2007    2006
     (In thousands)

Revenues

   $ 332,783      $ 191,931    $ 100,590

Expenses:

       

Operating expenses

     141,803        77,589      34,914

Depreciation and amortization expense

     47,558        24,505      9,761

General and administrative expense

     13,362        6,880      2,766

Interest expense

     1,871        —        —  

Impairment of property, plant and equipment

     30,000        —        —  
                     

Total expenses

     234,594        108,974      47,441
                     

Gain on sale of assets

     5,541        —        —  

Other income

     278        —        —  
                     

Income before income tax expense

     104,008        82,957      53,149

Income tax (benefit) expense

     (61,287     31,109      19,931
                     

Net income

   $ 165,295      $ 51,848    $ 33,218
                     

 

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL/DIVISION EQUITY

YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

 

     Division
Equity
    General
Partner
Interest
   Limited
Partner
Interest
   Total
Partners’
Capital
     (In thousands)

Balance at January 1, 2006

   $ 129,461      $ —      $ —      $ 129,461

Contributions from Parent

     163,272        —        —        163,272

Net income

     33,218        —        —        33,218
                            

Balance at December 31, 2006

     325,951        —        —        325,951

Contributions from Parent

     469,622        —        —        469,622

Net income

     51,848        —        —        51,848
                            

Balance at December 31, 2007

     847,421        —        —        847,421

Formation of partnership—allocation of division equity

     (847,421     16,948      830,473      —  

Contributions from Parent

     —          15,611      764,942      780,553

Net income

     —          3,306      161,989      165,295
                            

Balance at December 31, 2008

   $ —        $ 35,865    $ 1,757,404    $ 1,793,269
                            

 

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

 

     Year Ended December 31,  
     2008     2007     2006  
     (In thousands)  

Cash flows from operating activities

      

Net income

   $ 165,295      $ 51,848      $ 33,218   

Adjustments to reconcile net income to net cash provided by operating activities

      

Depreciation and amortization

     47,558        24,505        9,761   

Deferred income taxes

     (61,287     31,109        17,470   

Impairment of property, plant and equipment

     30,000        —          —     

Gain (loss) on sale of assets

     (5,541     —          —     

Other non-cash items

     (537     (603     —     

Changes in assets and liabilities, net of acquisitions

      

(Increase) decrease in accounts receivable

     (107,863     (22,192     (8,854

Increase (decrease) in other assets

     (138     (62     (18

Increase in accounts payable

     163,372        7,913        3,665   

Increase in accrued liabilities

     5,915        1,430        345   
                        

Net cash provided by operating activities

     236,774        93,948        55,587   
                        

Cash flows from investing activities

      

Proceeds from sale of assets

     17,615        —          —     

Additions to property, plant and equipment

     (1,402,449     (563,564     (218,843
                        

Net cash used in investing activities

     (1,384,834     (563,564     (218,843
                        

Cash flows from financing activities

      

Contributions from Parent

     780,553        469,622        163,272   

Proceeds from long-term debt borrowings

     508,900        —          —     

Payments on long-term debt borrowings

     (48,900     —          —     

Offering costs of long-term debt

     (10,494     —          —     
                        

Net cash provided by financing activities

     1,230,059        469,622        163,272   
                        

Net increase in cash and cash equivalents

     81,999        6        16   

Cash and cash equivalents

      

Beginning of year

     26        20        4   
                        

End of year

   $ 82,025      $ 26      $ 20   
                        

Supplemental disclosure of non-cash investing

      

Changes in accounts payable related to purchases of property, plant and equipment

   $ 58,458      $ 40,050      $ 30,248   

Changes in other liabilities related to asset retirement obligations

   $ 1,560      $ 4,032      $ —     

Supplemental disclosure of cash payments for interest

   $ 1,152      $ —        $ —     

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. Organization and Nature of Business

Organization

Chesapeake Midstream Development, L.P. (“CMD”) is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating operations of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly-owned subsidiary of Chesapeake Energy Corporation (“Parent”) were contributed to CMD. CEMI is the limited partner in CMD with a 98% ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner in CMD with a 2% ownership interest. CMM is a wholly owned subsidiary of CEMI.

CMD’s operations are conducted through wholly owned subsidiaries: Bluestem Gas Services, L.L.C., Texas Midstream Gas Services, L.L.C., Arkansas Midstream Gas Services Corp., AMGS, LLC, Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Gas Services, L.L.C., Oklahoma Midstream Gas Services L.L.C. and Appalachia Midstream Services L.L.C. These subsidiaries are held by Chesapeake Midstream Operating, L.L.C., which is a wholly owned subsidiary of CMD.

Nature of Business

CMD conducts its operations in Oklahoma, Texas, Louisiana, Arkansas, Kansas, New Mexico, Colorado, West Virginia and Pennsylvania. The underlying assets consist of approximately 2,900 miles of gathering pipeline, two CO 2 /H 2 S extraction facilities and eight small hydrocarbon dew point control facilities.

 

2. Basis of Presentation

The accompanying consolidated financial statements and related notes include the accounts of CMD and its subsidiaries, all of which are wholly-owned, and prior to February 28, 2008, include the assets, liabilities and operations of the midstream business that were contributed to CMD upon its formation presented on a carve out basis. As CMD and CEMI had common ownership, the assets and liabilities transferred were carried forward to CMD and are presented for all periods at their historical costs. At the date of the contribution to CMD, the division equity of the midstream business was reclassified as partners’ capital of CMD. All significant intercompany accounts and transactions have been eliminated in the preparation of the accompanying financial statements.

CMD’s financing requirements have been managed historically with cash generated by operations and equity contributions from the Parent. The Parent’s corporate level debt issuances and associated interest expense, which generally financed operations outside of CMD’s operations, are not reflected in CMD’s historical financial statements. On October 15, 2008 CMD entered into a Credit Facility Agreement with total commitments of $460 million. See Note 4 for further discussion. Prior to the completion of the Credit Facility in October 2008, all assets of the Parent, including the assets of CMD, were pledged as collateral on substantially all of the Parent’s debt. Payment of the debt of the Parent is not dependent upon the operations and cash flows of CMD. Upon the completion of the Credit Facility Agreement mentioned above, the assets of CMD ceased to be pledged as collateral with respect to the debt of the Parent.

Prior to the completion of the credit facility, the Parent provided cash management services to CMD through a centralized treasury system. As a result, all of CMD’s charges and cost allocations covered by the centralized treasury system were deemed to have been paid to the Parent in cash, during the period in which the cost was recorded in the financial statements. In addition, cash advanced by the Parent in excess of earnings by CMD is reflected as contributions from the Parent in the statements of partners’ capital/division equity. As a result of this accounting treatment, CMD’s December 31, 2007 working capital does not reflect any affiliate accounts payable for allocated operating and general and administrative expenses.

 

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Index to Financial Statements

Transactions between CMD and Parent or its affiliates have been identified in the financial statements as transactions between affiliates (see Notes 7 and 8).

The accompanying financial statements include allocated charges from CEMI to cover payroll and benefits for CEMI employees directly involved in gathering and treating operations. Operating expenses allocated by CEMI were $35.4 million, $13.0 million and $5.0 million for the years ended December 31, 2008, 2007 and 2006, respectively.

The accompanying financial statements include allocated charges from Parent for indirect corporate overhead to cover costs of functions such as legal, accounting, treasury, environmental safety, information technology and other corporate services. General and administrative charges allocated by Parent were $11.3 million, $6.9 million and $2.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. Management believes that the allocated general and administrative expense is representative of the costs and expenses incurred by Parent for CMD. Under the terms of an omnibus agreement, effective October 15, 2008, the overhead rate for CMD became $0.02/mmbtu. See Note 8 for a discussion of the allocation methods.

 

3. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. CMD makes significant estimates including: (1) estimated useful lives of assets, which impacts depreciation; (2) accruals related to revenues, expenses and capital costs; (3) liability and contingency accruals; and (4) cost allocations as described in Note 8. Although CMD’s management believes these estimates are reasonable, actual results could differ from its estimates.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, CMD considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Book overdrafts are checks that have been issued before the end of the period, but not presented to the bank for payment before the end of the period. At December 31, 2008 book overdrafts of $42.0 million were included in accounts payable. There were no book overdrafts at December 31, 2007.

Accounts Receivable

The majority of CMD’s accounts receivable relate to its gathering and treating activities. Accounts receivable included in the balance sheets are reflected net of an allowance for doubtful accounts, if warranted. At December 31, 2008 and 2007, no allowance for doubtful accounts was necessary.

Other Current Assets

Other current assets consist primarily of prepaid insurance.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for maintenance and repairs that do not add capacity or extend the useful life of an asset are expensed as incurred. The carrying value of the assets is based on estimates, assumptions and judgments relative to useful lives and salvage values. As assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in other income in the statements of operations.

 

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Index to Financial Statements

Certain of the gathering systems of CMD are subject to an agreement with a subsidiary of the Parent, which agreement provides CMD rights and obligations equivalent to a capital lease. Under the terms of the agreement, CMD has rights to the associated capital assets for as long as the assets are in operation. Specifically, CMD will pay all costs associated with the related gathering systems, including all capital costs, operating costs and direct and indirect overhead costs. In exchange for paying such costs and for the services it provides pursuant to this agreement, CMD receives revenues derived from operation of the gathering systems. At December 31, 2008, approximately $116.1 million ($115.0 million net of accumulated depreciation) of CMD’s gathering system assets are held under such agreement. Payments for capital costs under the agreement are made as the associated capital assets are constructed and, accordingly, CMD has no capital lease obligation liability associated with the assets held under this agreement as of December 31, 2008.

Property, plant and equipment consisted of the following at December 31:

 

     Estimated
Useful
Lives (Years)
   2008     2007  
     (In thousands)  

Gathering systems

   20    $ 2,450,298      $ 1,008,127   

Other fixed assets

   2 through 39      15,924        6,141   
                   

Property, plant and equipment, gross

        2,466,222        1,014,268   

Less: Accumulated depreciation

        (126,749     (48,467
                   

Property, plant and equipment, net

      $ 2,339,473      $ 965,801   
                   

Depreciation expense for the years ended December 31, 2008, 2007 and 2006 was $46.5 million, $24.5 million and $9.8 million, respectively.

CMD calculates its depreciation using the straight-line method, based on estimated useful lives of its assets. These estimates are based on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Uncertainties that impact these estimates include changes in laws and regulations relating to restoration and abandonment requirements, economic conditions, and supply and demand in the area. When assets are put into service, CMD makes estimates with respect to useful lives and salvage values that it believes are reasonable. However, subsequent events could cause CMD to change its estimates, thus impacting the future calculation of depreciation.

Impairment of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value, Assets are tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount the carrying value exceeds the fair value of the asset is recognized. Fair value is generally determined from estimated discounted future net cash flows. In 2008, CMD recorded an impairment of $30.0 million associated with certain of its treating assets.

Asset Retirement Obligations

CMD recognizes obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets at fair value in the period in which the liability is incurred.

 

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CMD has leased properties for the purpose of installing central compressor stations to aid in the transportation of natural gas. Certain of the lease agreements require CMD to restore the properties to their original condition at the expiration of the lease agreement. In these cases, CMD has estimated the costs to remove the facilities and otherwise restore the property to its original condition and has recorded a liability which is included in other long-term liabilities. The asset retirement cost is capitalized as part of the carrying amount of our gathering systems at its discounted fair value. The liability is then accreted each period until the liability is settled or the gathering system is sold, at which time the liability is reversed.

The components of the change in CMD’s asset retirement obligations are shown below:

 

     2008    2007
     (In thousands)

Asset retirement obligations, beginning of period

   $ 4,032    $ —  

Additions

     1,259      4,032

Accretion expense

     301      —  
             

Asset retirement obligations, end of period

   $ 5,592    $ 4,032
             

Environmental Matters

Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines, and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.

Revenue Recognition

CMD’s revenues consist of gathering revenues. Revenues are derived almost exclusively from related parties and are charged under short term contracts at market sensitive rates.

Gathering revenues consist of fees recognized for the gathering and transportation of natural gas to major intrastate or interstate pipelines and fees recognized for the removal of CO 2 and H 2 S from natural gas. Revenue for the gathering of natural gas is recognized when the service is performed and is based upon non-regulated rates and the related transport volumes and natural gas volumes requiring treatment.

Income Taxes

Parent and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. CMD and certain of its subsidiaries, as a partnership or limited liability companies, are not subject to federal income taxes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to the partners of CMD and, accordingly, do not result in a provision for income taxes in the accompanying financial statements.

Income taxes have been provided by CMD for its subsidiaries which are subject to federal and state income tax on the basis of their separate company income and deductions. Income taxes have also been provided for the operations of the midstream business prior to its contribution to CMD on February 28, 2008, during which period the operations were owned by CEMI and were subject to income taxes. Deferred income taxes have been provided for temporary differences between the book and tax carrying amounts of assets and liabilities held by taxable entities. These differences create taxable or tax deductible amounts for future periods. Current taxes payable were paid by the Parent and have been reflected as contributions from the Parent in the accompanying statements of partners’ capital/division equity. The Parent reimburses CMD for its net operating losses utilized in the completion of the Parent’s consolidated federal tax returns.

CMD had no uncertain tax positions at December 31, 2008 and 2007.

 

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Index to Financial Statements
4. Revolving Bank Credit Facility

On October 16, 2008, CMD closed on a revolving bank credit facility with total commitments of $460 million. CMD was restructured as part of this agreement as an unrestricted subsidiary of Parent. Twelve financial institutions are in the facility bank group. The facility matures in October 2013, at which time all amounts outstanding under the facility are due. The facility has initial availability of $460 million and may be expanded up to $750 million at CMD’s option, subject to additional bank participation. CMD is utilizing the facility to fund capital expenditures associated with building additional natural gas gathering and other systems and for general corporate purposes related to CMD’s operations. As of December 31, 2008, CMD had $460 million in outstanding borrowings under the credit facility. All CMD assets are pledged as collateral under this agreement. Borrowings under the facility bear interest at the greater of (i) the reference rate of Wells Fargo Bank, NA, (ii) the federal funds effective rate plus 0.50%, or (iii) the London Interest Bank Offered Rate (LIBOR) plus 1.50%. The unused portion of the facility is subject to a commitment fee that varies from 0.30% to 0.45%.

The credit facility agreement contains various covenants and restrictive provisions which limit the ability of CMD and its subsidiaries to incur additional indebtedness, make investments or loans and create liens. The credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined) not to exceed 3.50 to 1, and an EBITDA (as defined) to interest expense coverage ratio of not less than 2.50 to 1. As defined by the credit facility agreement, CMD’s indebtedness to EBITDA ratio was 2.60 to 1 and its EBITDA to interest expenses coverage ratio was 9.33 to 1 at December 31, 2008. If CMD or its subsidiaries should fail to perform their obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. The credit facility agreement also has cross default provisions that apply to other indebtedness CMD and its subsidiaries may have with an outstanding principal amount in excess of $15 million.

Based on the borrowing rates currently available to CMD for debt with similar terms and maturities, the carrying value of CMD’s long term debt approximates its fair value.

 

5. Stock-Based Compensation

Parent’s stock-based compensation programs consist of restricted stock and stock options issued to employees and non-employee directors. To the extent compensation cost relates to employees directly involved in gathering or treating operations, such amounts are charged to CMD directly and are reflected as operating expenses. Included in operating expenses is stock based compensation of $3.6 million, $2.7 million and $0.7 million during the years ended December 31, 2008, 2007 and 2006, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to CMD through an overhead allocation and are reflected as general and administrative expenses.

Restricted Stock

Parent regularly issues shares of restricted common stock to employees. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. This value is amortized over the vesting period, which is generally four or five years from the date of grant.

Stock Options

Prior to 2005, Parent granted stock options under several stock compensation plans. Outstanding options expire ten years from the date of grant and vest over a four-year period. Effective January 1, 2006, Parent adopted the fair value recognition provisions issued by the FASB using the modified-prospective method. Under this method, compensation cost recognized in 2007 and 2008 includes: (1) compensation cost for all share-based payments granted through December 31, 2005, but for which the requisite service period had not been completed as of December 31, 2005, based on the estimated grant date fair value, and (2) compensation cost for share-based payments granted subsequent to December 31, 2005, based on the estimated grant date fair value.

 

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Index to Financial Statements
6. Income Taxes

Income tax (benefit) expense for the years ended December 31, 2008, 2007 and 2006 is as follows:

 

     2008     2007    2006
     (In thousands)

Current

   $ —        $ —      $ 2,461

Deferred

     (61,287     31,109      17,470
                     

Total income tax (benefit) expense presented in the Statement of Operations

   $ (61,287   $ 31,109    $ 19,931
                     

Reconciliation of income tax expense at the U.S. Federal Statutory Income Tax Rate to actual tax expense (Statutory Rate Reconciliation) for the years ended December 31, 2008, 2007 and 2006 is as follows:

 

     2008     2007     2006  
     (In thousands)  

Income tax expense, computed at the statutory rate of 35%

   $ 36,403      $ 29,035      $ 18,602   

Effect of state income tax, net of federal income tax effect

     1,022        2,074        1,329   

Effect of non-taxable entities

     (12,555     —          —     

Effect of change in tax status (1)

     (86,157     —          —     
                        

Total income tax (benefit) expense

   $ (61,287   $ 31,109      $ 19,931   
                        

Effective tax rate

     (58.93 )%      37.50     37.50
                        

 

(1) Certain deferred tax liabilities were eliminated and recognized in earnings as a result of the change in tax status of CMD and its subsidiaries.

Net deferred income tax liability components for the years ended December 31, 2008 and 2007 are as follows:

 

     2008     2007  
     (In thousands)  

Net operating losses

   $ —        $ 6,036   

Accelerated depreciation rates

     (29,806     (72,615
                

Total net deferred income tax liabilities

   $ (29,806   $ (66,579
                

 

7. Major Customers and Concentration of Credit Risk

Financial instruments that potentially subject CMD to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2008, cash and cash equivalents were invested in money market funds with investment grade ratings. CEMI accounted for 99%, 97% and 97% of CMD’s revenues for the years ended December 31, 2008, 2007 and 2006, respectively, and, as such almost all of CMD’s accounts receivable are due from CEMI. CMD believes that a loss of this customer would have a material impact on its operating results as there can be no assurance that CMD would be able to identify and access a replacement market in a timely fashion or at comparable margins.

 

8. Transactions with Affiliates

In the normal course of business, CMD provides natural gas gathering and treating services to Parent and its affiliates. Revenues are derived almost exclusively from Parent, which includes volumes attributable to third-party interest owners that participate in Parent’s operated wells, and are charged under short term contracts at market sensitive rates.

 

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Index to Financial Statements

Certain of CMD’s gathering assets are held under an agreement with a subsidiary of the Parent. See Note 3 for discussion of the agreement.

In addition, Parent and its affiliates provide certain services to CMD including legal, accounting, treasury, information technology and administration. The employees supporting CMD’s operations are employees of CEMI or the Parent. CMD’s financial statements include costs allocated to it by Parent and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Parent’s centralized general and administrative functions. Prior to the completion of the credit facility, costs allocated to CMD were based on identification of Parent’s resources which directly benefit CMD and its proportionate share of costs based on CMD’s estimated usage of shared resources and functions. Costs were allocated to CMD based on its proportionate share of Parent’s headcount, compensation expense, or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that CMD’s management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if CMD had been operated as a stand-alone entity. As part of the terms of the omnibus agreement, effective October 15, 2008, the overhead rate for CMD became $0.02/mmbtu.

 

9. Commitments and Contingencies

CMD leases certain real property, equipment and operating facilities under various operating leases. It also incurs costs associated with leased land, rights-of-way, permits and regulatory fees, the contracts for which generally extend beyond one year but can be cancelled at any time should they not be required for operations. Future non-cancellable commitments related to these items at December 31, 2008, are summarized below:

 

     Operating
Leases
     (In thousands)

Year Ending December 31

  

2009

   $ 2,666

2010

     1,513

2011

     1,195

2012

     1,085

2013

     1,085

Thereafter

     2,240
      

Future minimum lease payments

   $ 9,784
      

Rental expense related to leases was $49.9 million, $26.3 million and $13.7 million for the years ended December 31, 2008, 2007 and 2006, respectively.

CMD is from time to time subject to various legal actions and claims incidental to its business, including those arising out of employment-related matters. CMD believes that these routine legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows of CMD. Once CMD determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to its estimate of the likely exposure. CMD did not have an accrual for legal settlements as of December 31, 2008, 2007 and 2006.

 

10. Environmental Remediation

The Parent maintains insurance of various types with varying levels of coverage that it considers adequate under the circumstances to cover the operations and properties of its subsidiaries. The insurance policies are subject to deductibles and retention levels that CMD considers reasonable. Consistent with insurance coverage generally available in the industry, in certain circumstances CMD’s insurance policies provide limited coverage

 

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Index to Financial Statements

for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Although CMD maintains a program designed to prevent and, as applicable, to detect and address such releases promptly, damages and liabilities incurred due to environmental releases from its assets may substantially affect its business.

At December 31, 2008 and 2007, CMD was not aware of any existing conditions that may cause it to incur significant expenditures in the future for the remediation of existing contamination. As such, CMD has not reflected in the accompanying financial statements any liabilities for environmental obligations to be incurred in the future based on existing contamination. Changes in CMD’s estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

 

11. Recently Issued Accounting Standards

In December 2007, the FASB issued guidance related to business combinations that requires assets acquired and liabilities assumed to be measured at fair value as of the acquisition date, acquisition-related costs incurred prior to the acquisition to be expensed and contractual contingencies to be recognized at fair value as of the acquisition date. This statement is effective for financial statements issued for fiscal years beginning after December 15, 2008. CMD will comply with this statement prospectively in accounting for future business combinations.

 

12. Subsequent Event

On January 29, 2009, February 23, 2009, and March 9, 2009, the Parent made cash contributions of $150 million, $50 million and $370 million, respectively, to CMD to fund capital expenditures and operations.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of Chesapeake Midstream Partners, L.P.:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Chesapeake Midstream Partners, L.P. at February 12, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Chesapeake Midstream Partners, L.P.’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 15, 2010

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

BALANCE SHEET

 

    February 12, 2010

Assets

 

Cash

  $ 1,000
     

Total Assets

  $ 1,000
     

Partners’ Equity

 

Limited Partner Equity

  $ 980

General Partner Equity

    20
     

Total Partners’ Equity

  $ 1,000
     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the accompanying note to the balance sheet

 

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Index to Financial Statements

NOTE TO FINANCIAL STATEMENT

 

1. Nature of Operations

Chesapeake Midstream Partners, L.P. (the “Partnership”) was formed on January 21, 2010.

On February 12, 2010, Chesapeake Midstream Ventures, L.L.C. contributed $980 to the Partnership in exchange for a 98% limited partner interest and Chesapeake Midstream GP, L.L.C. contributed $20 in exchange for a 2% general partner interest.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Member of Chesapeake Midstream GP, L.L.C.:

In our opinion, the accompanying balance sheet presents fairly, in all material respects, the financial position of Chesapeake Midstream GP, L.L.C. at February 12, 2010 in conformity with accounting principles generally accepted in the United States of America. This financial statement is the responsibility of Chesapeake Midstream GP, L.L.C.’s management. Our responsibility is to express an opinion on this financial statement based on our audit. We conducted our audit of this statement in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the balance sheet is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, and evaluating the overall balance sheet presentation. We believe that our audit provides a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 15, 2010

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM GP, L.L.C.

BALANCE SHEET

 

    February 12, 2010

Assets

 

Cash

  $ 980

Investments in Chesapeake Midstream Partners, L.P.

  $ 20
     

Total Assets

  $ 1,000
     

Member’s Equity

 

Member’s Equity

  $ 1,000
     

Total Members’ Equity

  $ 1,000
     

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See the accompanying note to the balance sheet

 

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NOTE TO FINANCIAL STATEMENT

 

1. Nature of Operations

Chesapeake Midstream GP, L.L.C. (the “Company”) is a limited liability company formed on January 21, 2010 to become the general partner of Chesapeake Midstream Partners L.P. (the “Partnership”). The Company owns a 2% general partnership interest in the Partnership.

On February 12, 2010, Chesapeake Midstream Ventures, L.L.C., as sole member, contributed $1,000 to the Company in exchange for a 100% membership interest. The Company contributed $20 to the Partnership in exchange for a 2% general partner interest. There have been no other transactions involving the Company.

 

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APPENDIX A

AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP

OF CHESAPEAKE MIDSTREAM PARTNERS, L.P.

 

[To Be Provided By Amendment]

 

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Index to Financial Statements

APPENDIX B

GLOSSARY OF TERMS

adjusted operating surplus :  Adjusted operating surplus consists of:

(a) for any period, operating surplus generated with respect to that period; less

(b) any net increase in working capital borrowings with respect to that period; less

(c) any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

(d) any net decrease in working capital borrowings with respect to that period; plus

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

Cash payments by any of our customers, including Chesapeake and Total, to settle a shortfall associated with any minimum volume commitment under a gas gathering agreement will be operating surplus in the quarter in which they are actually received. An estimated, prorated amount of such payments, however, may be included in adjusted operating surplus by our general partner in the manner generally described below. As described elsewhere in this prospectus, the cash settlement of any shortfall in actual volumes associated with the minimum volume commitments of Chesapeake and Total will be settled in the year following the calendar year to which such volume commitments relate. In order to accommodate the rolling-four quarter test associated with expiration of the subordination period (relative to any after the period payment associated with a shortfall in any minimum volume commitment), to the extent that the actual volumes (associated with a minimum volume commitment) in a particular quarter or quarters are less than the prorated minimum volume commitment amount for such period, our general partner may add to adjusted operating surplus for such period an amount equal to such shortfall in actual volumes, multiplied by the then applicable gathering rate. The quarterly shortfall payment estimate would be adjusted each subsequent quarter based on the level of actual volumes for such subsequent quarter and the preceding quarters of the period that remain subject to a minimum volume commitment (as compared to the prorated volume commitment for such period). If the estimated amount of shortfall payments used by our general partner to increase adjusted operating surplus in prior quarters is more than any shortfall amount actually paid for a minimum volume commitment period as finally determined, and subordinated units remain outstanding, then adjusted operating surplus shall be adjusted in each such quarter to give effect to the actual amount of the payment as if it had been received in such quarter to cover the shortfall in such quarter.

available cash :  For any quarter ending prior to liquidation:

(a) the sum of:

(1) all cash and cash equivalents of Chesapeake Midstream Partners, L.P. and its subsidiaries on hand at the end of that quarter; and

(2) if our general partner so determines all or a portion of any additional cash or cash equivalents of Chesapeake Midstream Partners, L.P. and its subsidiaries on hand on the date of determination of available cash for that quarter;

(b) less the amount of cash reserves established by our general partner to:

(1) provide for the proper conduct of the business of Chesapeake Midstream Partners, L.P. and its subsidiaries (including reserves for future capital expenditures and for future credit needs of Chesapeake Midstream Partners, L.P. and its subsidiaries) after that quarter;

(2) comply with applicable law or any debt instrument or other agreement or obligation to which Chesapeake Midstream Partners, L.P. or any of its subsidiaries is a party or its assets are subject; and

 

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Index to Financial Statements

(3) provide funds for minimum quarterly distributions and cumulative common unit arrearages for any one or more of the next four quarters;

provided, however , that our general partner may not establish cash reserves pursuant to clause (b)(3) immediately above unless our general partner has determined that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon for that quarter; and provided, further, that disbursements made by us or any of our subsidiaries or cash reserves established, increased or reduced after the end of that quarter but on or before the date of determination of available cash for that quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining available cash, within that quarter if our general partner so determines.

Bcf :  Billion cubic feet of natural gas.

Bcfe : Billion cubic feet equivalent.

capital account :  The capital account maintained for a partner under the partnership agreement. The capital account of a partner for a common unit, a subordinated unit, an incentive distribution right or any other partnership interest will be the amount which that capital account would be if that common unit, subordinated unit, incentive distribution right or other partnership interest were the only interest in Chesapeake Midstream Partners, L.P. held by a partner.

capital surplus : All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed since the closing of the initial public offering equals the operating surplus from the closing of the initial public offering through the end of the quarter immediately preceding that distribution. Any excess available cash distributed by us on that date will be deemed to be capital surplus.

closing price : The last sale price on a day, regular way, or in case no sale takes place on that day, the average of the closing bid and asked prices on that day, regular way, in either case, as reported in the principal consolidated transaction reporting system for securities listed or admitted to trading on the principal national securities exchange on which the units of that class are listed or admitted to trading. If the units of that class are not listed or admitted to trading on any national securities exchange, the last quoted price on that day. If no quoted price exists, the average of the high bid and low asked prices on that day in the over-the-counter market, as reported by the New York Stock Exchange or any other system then in use. If on any day the units of that class are not quoted by any organization of that type, the average of the closing bid and asked prices on that day as furnished by a professional market maker making a market in the units of the class selected by our board of directors. If on that day no market maker is making a market in the units of that class, the fair value of the units on that day as determined reasonably and in good faith by our board of directors.

cumulative common unit arrearage : The amount by which the minimum quarterly distribution for a quarter during the subordination period exceeds the distribution of available cash from operating surplus actually made for that quarter on a common unit, cumulative for that quarter and all prior quarters during the subordination period.

current market price : For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

interim capital transactions : The following transactions if they occur prior to liquidation:

(a) borrowings, refinancings or refundings of indebtedness and sales of debt securities (other than for items purchased on open account in the ordinary course of business) by Chesapeake Midstream Partners, L.P. or any of its subsidiaries;

(b) sales of equity interests by Chesapeake Midstream Partners, L.P. or any of its subsidiaries;

 

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(c) sales or other voluntary or involuntary dispositions of any assets of Chesapeake Midstream Partners, L.P. or any of its subsidiaries (other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and sales or other dispositions of assets as a part of normal retirements or replacements);

(d) the termination of interest rate swap agreements;

(e) capital contributions; and

(f) corporate reorganizations or restructurings.

MMBtu : One million British Thermal Units.

MMBtu/d : One million British Thermal Units per day.

MMcf : One million cubic feet of natural gas.

MMcf/d : One million cubic feet per day.

NGLs : Natural gas liquids. The combination of ethane, propane, butane and natural gasolines that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

operating expenditures : All of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner, reimbursement of expenses to Chesapeake for services pursuant to the omnibus agreement or personnel provided to us under the employee secondment agreement, payments made in the ordinary course of business under interest rate swap agreements or commodity hedge contracts, manager and officer compensation, repayment of working capital borrowings, debt service payments and estimated maintenance capital expenditures, provided that operating expenditures will not include:

 

   

repayment of working capital borrowings deducted from operating surplus pursuant to the last bullet point of the definition of operating surplus below when such 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 our partners (including distributions in respect of our incentive distribution rights); or

 

   

non-pro rata purchases of units of any class made with the proceeds of a substantially concurrent equity issuance.

operating surplus : Operating surplus consists of:

 

   

             million (as described below); plus

 

   

all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions, which include the following:

 

   

borrowings that are not working capital borrowings,

 

   

sales of equity and debt securities,

 

   

sales or other dispositions of assets outside the ordinary course of business,

 

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Index to Financial Statements

 

   

capital contributions received, and

 

   

corporate reorganizations or restructurings;

provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; 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 issued to finance all or a portion of the construction, acquisition, improvement or replacement of a capital asset (such as equipment or facilities) during the period beginning on the date that we enter into a binding obligation to commence the construction, acquisition or improvement of a capital improvement or replacement of a capital asset and ending on the earlier to occur of the date the capital improvement or capital asset commences commercial service or the date that it is abandoned or disposed of; less

 

   

all of our operating expenditures (as defined above) after the closing of this offering; less

 

   

the amount of cash reserves established by our 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

play : A proven geological formation that contains commercial amounts of petroleum and/or natural gas.

receipt point : The point where production is received by or into a gathering system or transportation pipeline.

residue gas : The natural gas remaining after being processed or treated.

sour gas : Gas containing more than four parts per million of hydrogen sulfide.

Tcf : One trillion cubic feet of natural gas.

throughput : The volume of natural gas transported or passing through a pipeline, plant, terminal or other facility in an economically meaningful period of time.

wellhead : The equipment at the surface of a well used to control the well’s pressure; the point at which the hydrocarbons and water exit the ground.

 

Appendix B-4


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Index to Financial Statements

 

 

[ Inside Back Cover Art to Come]

 

 

 

 

 


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             Common Units

Representing Limited Partner Interests

LOGO

Chesapeake Midstream Partners, L.P.

 

 

 

Citi   Morgan Stanley

 

 

 

 


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Index to Financial Statements

Part II

Information required in the registration statement

 

ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts and commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

 

SEC registration fee

   $ 24,599

FINRA filing fee

     35,000

Printing and engraving expenses

     *

Fees and expenses of legal counsel

     *

Accounting fees and expenses

     *

Transfer agent and registrar fees

     *

New York Stock Exchange listing fee

     *

Miscellaneous

     *
      

Total

     *
      

 

* To be provided by amendment.

 

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.

Chesapeake Midstream Partners, L.P.

Subject to any terms, conditions or restrictions set forth in the partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against any and all claims and demands whatsoever. The section of the prospectus entitled “The Partnership Agreement—Indemnification” discloses that we will generally indemnify officers, directors and affiliates of our general partner to the fullest extent permitted by the law against all losses, claims, damages or similar events and is incorporated herein by reference.

Under our partnership agreement, in most circumstances, we will indemnify the following persons, to the fullest extent permitted by law, from and against all losses, claims, damages or similar events:

 

   

our general partner;

 

   

any departing general partner;

 

   

any person who is or was an affiliate of our general partner or any departing general partner;

 

   

any person who is or was a director, officer, member, partner, fiduciary or trustee of any entity set forth in the preceding three bullet points;

 

   

any person who is or was serving as director, officer, member, partner, fiduciary or trustee of another person at the request of our general partner, any departing general partner, an affiliate of our general partner or an affiliate of any departing general partners; and

 

   

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

 

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Additionally, pursuant to the omnibus agreement, we will be entitled to indemnification for certain liabilities, and we will be required to indemnify Chesapeake for certain liabilities.

We have agreed to indemnify Chesapeake and certain affiliates of Chesapeake against any loss or expense with respect to certain surety bonds issued for our benefit and for which we are obligated to provide indemnity insurance to Chesapeake. We may also be required to indemnify Chesapeake in connection with future surety bond issuances made for our benefit. The section of the prospectus entitled “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Surety Bond Indemnification Agreement” describes in more detail our obligation to indemnify Chesapeake with respect to our surety bond indemnification agreement and is incorporated herein by reference.

The underwriting agreement to be entered into in connection with the sale of the securities offered pursuant to this registration statement, the form of which has been filed as an exhibit to this registration statement, provides for indemnification of Chesapeake and our general partner, their officers and directors, and any person who controls Chesapeake and our general partner, including indemnification for liabilities under the Securities Act.

Chesapeake Midstream GP, L.L.C.

Section 18-108 of the Delaware Limited Liability Company Act (the “Delaware LLC Act”) provides that, subject to such standards and restrictions, if any, as are set forth in its limited liability company agreement, a Delaware limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Chesapeake Midstream GP, L.L.C., our general partner, provides that our general partner shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he or she is or was a director or officer of our general partner, or is or was serving at the request of our general partner as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise (an “indemnitee”), against expenses (including reasonable attorney’s fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such indemnitee in connection with such action, suit or proceeding to the full extent permitted by the Delaware LLC Act, upon such determination having been made as to such indemnitee’s good faith and conduct as is required by the Delaware LLC Act. The limited liability company agreement of our general partner also provides that expenses incurred in defending a civil or criminal action, suit or proceeding shall be paid by our general partner in advance of the final disposition of such action, suit or proceeding to the extent, if any, authorized by our general partner’s sole member in accordance with the provisions of the Delaware LLC Act, upon receipt of an undertaking by or on behalf of the indemnitee to repay such amount unless it shall ultimately be determined that indemnitee is entitled to be indemnified by our general partner. Officers, directors and affiliates of our general partner are also indemnified by us, as described above.

Our general partner will enter into indemnification agreements (each, an “Indemnification Agreement”) with each of its officers and directors. Each Indemnification Agreement provides that our general partner will indemnify and hold harmless each officer and director against all expense, liability and loss (including attorneys’ fees, judgments, fines or penalties and amounts to be paid in settlement) actually and reasonably incurred or suffered by an officer or director in connection with serving in their capacity as officers and directors of our general partner (or of any subsidiary of our general partner) or in any capacity at the request of our general partner or its board of directors to the fullest extent permitted by Section 18-108 of the Delaware LLC Act, as the same exists or may be amended (but, in the case of any such amendment, only to the extent that such amendment permits our general partner to provide broader indemnification rights than such law permitted our general partner to provide prior to such amendment), or by other applicable law as then in effect. Each Indemnification Agreement also provides that our general partner must advance payment of certain expenses to an officer or director, including fees of counsel, in advance of final disposition of any proceeding subject to receipt of an undertaking from such officer or director to return such advance if it is ultimately determined that such officer or director is not entitled to indemnification.

 

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Our general partner will purchase insurance covering its officers and directors against liabilities asserted and expenses incurred in connection with their activities as officers and directors of our general partner or any of its direct or indirect subsidiaries.

Chesapeake Energy Corporation

Section 1031 of the Oklahoma General Corporation Act generally provides that an Oklahoma corporation has the power to indemnify (a) any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative, other than an action by or in the right of the corporation, by reason of the fact that the person is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses, including attorneys’ fees, judgments, fines, and amounts paid in settlement actually and reasonably incurred by the person in connection with the action, suit, or proceeding if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe the conduct was unlawful; and (b) any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that the person is or was a director, officer, employee, or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise against expenses, including attorneys’ fees, actually and reasonably incurred by the person in connection with the defense or settlement of an action or suit if the person acted in good faith and in a manner the person reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue, or matter as to which the person shall have been adjudged to be liable to the corporation unless and only to the extent that the court in which the action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, the person is fairly and reasonably entitled to indemnity for expenses which the court shall deem proper.

Article VIII of Chesapeake’s restated certificate of incorporation provides that Chesapeake shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of Chesapeake) by reason of the fact that he or she is or was a director, officer, employee or agent of Chesapeake or is or was serving at the request of Chesapeake as a director, officer, employee or agent of another corporation, partnership, joint venture or other enterprise against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him or her in connection with such action, suit or proceeding, if he or she acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interest of Chesapeake and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his conduct was unlawful. In addition, Article VI of Chesapeake’s amended and restated bylaws generally provides that Chesapeake shall indemnify any person who is a director, officer, employee or agent of Chesapeake or is or was serving at the request of Chesapeake as a director, officer, employee or agent of another corporation, partnership, joint venture or other enterprise to the fullest extent permitted by Section 1031 of the Oklahoma General Corporation Act.

Chesapeake has entered into indemnity agreements with each of its officers and directors, including Messrs. J. Mike Stice, Aubrey K. McClendon and Marcus C. Rowland, which generally provide that Chesapeake shall indemnify its officers and directors in connection with serving in their capacity as an officer, director, employee or agent of Chesapeake or an affiliate or serving at the request of Chesapeake as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise to the fullest extent permitted by law. In addition, Chesapeake provides liability insurance for each of its directors and executive officers.

 

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ITEM 15 . RECENT SALES OF UNREGISTERED SECURITIES.

On February 12, 2010, in connection with the formation of Chesapeake Midstream Partners, L.P. (the “Partnership”), the Partnership issued to (i) its general partner the 2.0% general partner interest in the Partnership for $20 and (ii) Chesapeake Midstream Ventures, L.L.C. the 98.0% limited partner interest in the Partnership for $980. The issuance was exempt from registration under Section 4(2) of the Securities Act. There have been no other sales of unregistered securities within the past three years.

 

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Index to Financial Statements
ITEM 16 . EXHIBITS.

The following documents are filed as exhibits to this registration statement:

 

Exhibit
Number

      

Description

  1.1*      Form of Underwriting Agreement
  3.1      Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.
  3.2*      Form of Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. (included as Appendix A in the prospectus included in this Registration Statement)
  3.3      Certificate of Formation of Chesapeake Midstream GP, L.L.C.
  3.4*      Form of Amended and Restated Limited Liability Company Agreement of Chesapeake Midstream GP, L.L.C.
  5.1*      Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8.1*      Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*      Form of Credit Agreement
10.2*      Chesapeake Gas Gathering Agreement
10.3*      Total Gas Gathering Agreement
10.4*      Form of Contribution Agreement
10.5*      Form of Omnibus Agreement
10.6*      Form of Gas Compressor Master Rental and Servicing Agreement
10.7*      Form of Inventory Purchase Agreement
10.8*      Form of Marketing and Noncompete Agreement
10.9*      Form of Master Recoupment, Netting and Setoff Agreement
10.10*      Form of Trademark License Agreement
10.11*      Form of Employee Transfer Agreement
10.12*      Form of Employee Secondment Agreement
10.13*      Form of Shared Services Agreement with respect to J. Mike Stice
10.14*      Employment Agreement of J. Mike Stice
10.15*      Employment Agreement of Robert S. Purgason
10.16*      Employment Agreement of David C. Shiels
10.17*      Form of Registration Rights Agreement
10.18*      Form of Chesapeake Midstream Management Incentive Compensation Plan
10.19*      Form of Chesapeake Midstream Long-Term Incentive Plan
10.20*      Form of Indemnification Agreement
21.1*      List of Subsidiaries of Chesapeake Midstream Partners, L.P.
23.1      Consent of PricewaterhouseCoopers LLP
23.2*      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3*      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1      Powers of Attorney (contained on the signature page to this registration statement)

 

* To be filed by amendment.

 

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ITEM 17 . UNDERTAKINGS.

The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

The undersigned registrant undertakes to send to each common unitholder, at least on an annual basis, a detailed statement of any transactions with Chesapeake or its subsidiaries, and of fees, commissions, compensation and other benefits paid, or accrued to Chesapeake or its subsidiaries for the fiscal year completed, showing the amount paid or accrued to each recipient and the services performed.

The registrant undertakes to provide to the common unitholders the financial statements required by Form 10-K for the first full fiscal year of operations of the company.

 

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Signatures

Pursuant to the requirements of the Securities Act of 1933, as amended, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Oklahoma City, State of Oklahoma, on February 16, 2010.

 

Chesapeake Midstream Partners, L.P.
By:  

Chesapeake Midstream GP, L.L.C.,

its general partner

By:  

/s/ J. M IKE S TICE

Name:   J. Mike Stice
Title:   Chief Executive Officer

Each person whose signature appears below appoints J. Mike Stice, Robert S. Purgason and David C. Shiels, and each of them, any of whom may act without the joinder of the other, as his true and lawful attorneys-in-fact and agents, with full power of substitution and re-substitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments (including post-effective amendments) to this Registration Statement and any Registration Statement (including any amendment thereto) for this offering that is to be effective upon filing pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them, or their or his substitute and substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed by the following persons in the capacities and the dates indicated.

 

Signature

  

Title

 

Date

/s/ J. M IKE S TICE

J. Mike Stice

   Chief Executive Officer (Principal Executive Officer)   February 16, 2010

/s/ D AVID C. S HIELS

David C. Shiels

   Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)   February 16, 2010

/s/ M ATTHEW C. H ARRIS

Matthew C. Harris

   Director   February 16, 2010

/s/ A UBREY K. M C C LENDON

Aubrey K. McClendon

   Director   February 16, 2010

/s/ M ARCUS C. R OWLAND

Marcus C. Rowland

   Director   February 16, 2010

/s/ W ILLIAM A. W OODBURN

William A. Woodburn

   Director   February 16, 2010

 

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Index to Financial Statements

Exhibit
Number

      

Description

  1.1*      Form of Underwriting Agreement
  3.1      Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.
  3.2*      Form of Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. (included as Appendix A in the prospectus included in this Registration Statement)
  3.3      Certificate of Formation of Chesapeake Midstream GP, L.L.C.
  3.4*      Form of Amended and Restated Limited Liability Company Agreement of Chesapeake Midstream GP, L.L.C.
  5.1*      Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered
  8.1*      Opinion of Vinson & Elkins L.L.P. relating to tax matters
10.1*      Form of Credit Agreement
10.2*      Chesapeake Gas Gathering Agreement
10.3*      Total Gas Gathering Agreement
10.4*      Form of Contribution Agreement
10.5*      Form of Omnibus Agreement
10.6*      Form of Gas Compressor Master Rental and Servicing Agreement
10.7*      Form of Inventory Purchase Agreement
10.8*      Form of Marketing and Noncompete Agreement
10.9*      Form of Master Recoupment, Netting and Setoff Agreement
10.10*      Form of Trademark License Agreement
10.11*      Form of Employee Transfer Agreement
10.12*      Form of Employee Secondment Agreement
10.13*      Form of Shared Services Agreement with respect to J. Mike Stice
10.14*      Employment Agreement of J. Mike Stice
10.15*      Employment Agreement of Robert S. Purgason
10.16*      Employment Agreement of David C. Shiels
10.17*      Form of Registration Rights Agreement
10.18*      Form of Chesapeake Midstream Management Incentive Compensation Plan
10.19*      Form of Chesapeake Midstream Long-Term Incentive Plan
10.20*      Form of Indemnification Agreement
21.1*      List of Subsidiaries of Chesapeake Midstream Partners, L.P.
23.1      Consent of PricewaterhouseCoopers LLP
23.2*      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
23.3*      Consent of Vinson & Elkins L.L.P. (contained in Exhibit 8.1)
24.1      Powers of Attorney (contained on the signature page to this registration statement)

 

* To be filed by amendment.

 

II-8

Exhibit 3.1

CERTIFICATE OF LIMITED PARTNERSHIP

OF

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

January 21, 2010

This Certificate of Limited Partnership, dated January 21, 2010, has been duly executed and is filed pursuant to Section 17-201 of the Delaware Revised Uniform Limited Partnership Act (the “ Act ”) to form a limited partnership (the “ Partnership ”) under the Act.

1. Name. The name of the Partnership is “Chesapeake Midstream Partners, L.P.”

2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 17-104 of the Act is:

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be maintained by Section 17-104 of the Act are:

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

3. General Partner. The name and the business address of the general partner are:

Chesapeake Midstream GP, L.L.C.

777 NW Grand Boulevard

Oklahoma City, Oklahoma 73118

4. This Certificate shall become effective upon filing with the Secretary of State of the State of Delaware.

[Signature Page Follows]


IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Limited Partnership as of the date first written above.

 

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

By:

  Chesapeake Midstream GP, L.L.C.,
  its General Partner

By:

 

/s/ Jennifer Grigsby

Name:

  Jennifer Grigsby

Title:

  Corporate Secretary

 

Signature Page to

Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.

Exhibit 3.3

CERTIFICATE OF FORMATION

OF

CHESAPEAKE MIDSTREAM GP, L.L.C.

January 21, 2010

This Certificate of Formation, dated January 21, 2010, has been duly executed and is filed pursuant to Section 18-201 of the Delaware Limited Liability Company Act (the “ Act ”) to form a limited liability company (the “ Company ”) under the Act.

1. Name. The name of the Company is “Chesapeake Midstream GP, L.L.C.”

2. Registered Office; Registered Agent. The address of the registered office required to be maintained by Section 18-104 of the Act is:

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

The name and address of the registered agent for service of process required to be maintained by Section 18-104 of the Act are:

The Corporation Trust Company

Corporation Trust Center

1209 Orange Street

Wilmington, Delaware 19801

[ Signature Page Follows ]


IN WITNESS WHEREOF, the undersigned has duly executed this Certificate of Formation as of the date first written above.

.

CHESAPEAKE MIDSTREAM GP, L.L.C

By:  

/s/ Jennifer Grigsby

Name:  

Jennifer Grigsby

Organizer

Signature Page to

Certificate of Formation of Chesapeake Midstream GP, L.L.C.

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the use in this Registration Statement on Form S-1 of i) our report dated April 6, 2009 relating to the audit of the consolidated financial statements of Chesapeake Midstream Development, L.P. as of December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008, ii) our report dated February 15, 2010 relating to the audit of the balance sheet of Chesapeake Midstream Partners, L.P. as of February 15, 2010, and iii) our report dated February 15, 2010 relating to the audit of the balance sheet of Chesapeake Midstream GP, L.L.C. as of February 15, 2010, which appear in such Registration Statement. We also consent to the references to us under the heading “Experts” in such Registration Statement.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

February 16, 2010