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Index to Financial Statements

As filed with the Securities and Exchange Commission on May 24, 2010

Registration No. 333-164905

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 3

to

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 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(3)
Common units representing limited partner interests				$ 488,750,000		$ 34,849

(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).

(3)

The total registration fee includes $24,599 that was previously paid for the registration of $345,000,000 of proposed maximum aggregate offering price in the filing of the Registration Statement on February 16, 2010 and $10,250 for the registration of an additional $143,750,000 of proposed maximum aggregate offering price registered hereby.

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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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 MAY 24, 2010

             Common Units

Representing Limited Partner Interests

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 have applied to list our common units on the New York Stock Exchange under the symbol “CHKM.”

 

 

 

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 20. 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.

 

•

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, our cash available for distribution to you would be substantially reduced.

 

 

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 0.75% of the gross proceeds of this offering, or approximately $            .

 

 

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

 

 

Joint Book-Running Managers

UBS Investment Bank    Citi    Morgan Stanley

BofA Merrill Lynch    Barclays Capital    Credit Suisse     Goldman, Sachs & Co.    Wells Fargo Securities

Senior Co-Managers

BBVA Securities    BMO Capital Markets    Deutsche Bank Securities    Raymond James     RBS    Scotia Capital

Junior Co-Managers

BNP PARIBAS    Comerica Securities    Credit Agricole CIB    ING    Mitsubishi UFJ Securities

Piper Jaffray    RBC Capital Markets    SunTrust Robinson Humphrey    TD Securities

 

 

The date of this prospectus is                     , 2010.

 

 

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		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		4
Our Relationship with GIP		6
Risk Factors		6
Principal Executive Offices and Internet Address		7
Formation Transactions and Partnership Structure		8
Our Management		10
Summary of Conflicts of Interest and Fiduciary Duties		10
The Offering		11
Summary Historical and Unaudited Pro Forma Financial and Operating Data		16
Non-GAAP Financial Measure		18
Risk Factors		20
Risks Related to Our Business		20
Risks Inherent in an Investment in Us		35
Tax Risks to Common Unitholders		42
Use of Proceeds		47
Capitalization		48
Dilution		49
Our Cash Distribution Policy and Restrictions on Distributions		50
General		50
Our Minimum Quarterly Distribution		51
Unaudited Pro Forma Available Cash for the Year Ended December  31, 2009 and the Twelve Months Ended March 31, 2010		53
Partnership Unaudited Pro Forma Available Cash		54
Estimated Adjusted EBITDA for Twelve Months Ending June 30, 2011		55
Partnership Statement of Estimated Adjusted EBITDA		56
Assumptions and Considerations		57
Provisions of Our Partnership Agreement Relating to Cash Distributions		62
Distributions of Available Cash		62
Operating Surplus and Capital Surplus		63
Capital Expenditures		65
Subordination Period		66
Distributions of Available Cash From Operating Surplus During the Subordination Period		68
Distributions of Available Cash From Operating Surplus After the Subordination Period		69
General Partner Interest and Incentive Distribution Rights		69
Percentage Allocations of Available Cash From Operating Surplus		70
General Partner’s Right to Reset Incentive Distribution Levels		70
Distributions From Capital Surplus		72
Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels		73
Distributions of Cash Upon Liquidation		73
Selected Historical and Unaudited Pro Forma Financial and Operating Data		76
Management’s Discussion and Analysis of Financial Condition and Results of Operations		79
Overview		79
Chesapeake Midstream Partners, L.P., Our Predecessor and Successor		80
Our Gas Gathering Agreements		80

 

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		Page
Other Arrangements		83
How We Evaluate Our Operations		84
Items Impacting the Comparability of Our Financial Results		86
General Trends and Outlook		87
Results of Operations—Combined Overview		88
Liquidity and Capital Resources		95
Critical Accounting Policies and Estimates		99
Quantitative and Qualitative Disclosures About Market Risk		100
Recent Accounting Pronouncements		101
Industry		102
General		102
Service Types		102
Typical Contractual Arrangements		103
U.S. Natural Gas Fundamentals		104
Overview of Our Barnett Shale Region		105
Overview of Our Mid-Continent Region		106
Business		108
Our Partnership		108
Our Assets and Areas of Operation		109
Our Business Strategies		110
Our Competitive Strengths		112
Our Relationship with Chesapeake		113
Our Relationship with GIP		114
Chesapeake—Total Joint Venture		115
Our Assets		115
Competition		118
Safety and Maintenance		118
Regulation of Operations		119
Environmental Matters		120
Title to Properties and Rights-of-Way		124
Employees		125
Legal Proceedings		125
Management		126
Management of the Partnership		126
Directors and Executive Officers		128
Executive Compensation		130
Compensation of Directors		130
Compensation Discussion and Analysis		131
Elements and Mix of Compensation		132
Employment Agreements		134
Management Incentive Compensation Plan		137
Long-Term Incentive Plan		137
Relation of Compensation Policies and Practices to Risk Management		139
Security Ownership of Certain Beneficial Owners and Management		140
Certain Relationships and Related Party Transactions		142
Distributions and Payments to Our General Partner and Its Affiliates		142
Agreements with Affiliates		143
Review, Approval or Ratification of Transactions with Related Persons		154
Conflicts of Interest and Fiduciary Duties		155
Conflicts of Interest		155
Fiduciary Duties		160

 

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		Page
Description of the Common Units		163
The Units		163
Transfer Agent and Registrar		163
Transfer of Common Units		163
The Partnership Agreement		165
Organization and Duration		165
Purpose		165
Cash Distributions		165
Capital Contributions		165
Voting Rights		166
Applicable Law; Forum, Venue and Jurisdiction		167
Limited Liability		167
Issuance of Additional Securities		168
Amendment of the Partnership Agreement		169
Merger, Consolidation, Conversion, Sale or Other Disposition of Assets		171
Dissolution		172
Liquidation and Distribution of Proceeds		172
Withdrawal or Removal of Our General Partner		172
Transfer of General Partner Units		173
Transfer of Ownership Interests in the General Partner		174
Transfer of Incentive Distribution Rights		174
Change of Management Provisions		174
Limited Call Right		174
Non-Citizen Assignees; Redemption		175
Non-Taxpaying Assignees; Redemption		175
Meetings; Voting		175
Status as Limited Partner		176
Indemnification		176
Reimbursement of Expenses		177
Books and Reports		177
Right to Inspect Our Books and Records		177
Registration Rights		178
Operating Agreement of Chesapeake MLP Operating, L.L.C.		178
Units Eligible for Future Sale		179
Material Tax Consequences		181
Partnership Status		181
Limited Partner Status		183
Tax Consequences of Unit Ownership		183
Tax Treatment of Operations		188
Disposition of Common Units		189
Uniformity of Units		191
Tax-Exempt Organizations and Other Investors		192
Administrative Matters		193
State, Local, Foreign and Other Tax Considerations		195
Investment in Chesapeake Midstream Partners, L.P. by Employee Benefit Plans		196
Underwriting		198
Validity of the Common Units		203
Experts		203
Where You Can Find More Information		203
Forward-Looking Statements		203
Index to Financial Statements		F-1

 

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		Page
Appendix A: First 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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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 three months ended March 31, 2010, Chesapeake and its working interest partners accounted for approximately 95% of the natural gas volumes on our gathering systems and 97% of our revenues. 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.

The amount of cash available for distribution will also be reduced by the amount we reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake (including certain incremental costs and expenses we will incur as a result of being a publicly traded partnership, which we expect to initially be approximately $2.0 million per year), each pursuant to the services 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. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement.” In addition, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses. 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.”

 

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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, 2009 or the twelve months ended March 31, 2010.

The amount of pro forma available cash generated during each of the year ended December 31, 2009 and the twelve months ended March 31, 2010 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     % and     %, respectively, 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 based on our pro forma results for 2009 and the twelve months ended March 31, 2010, 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 twelve months ending June 30, 2011. 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 March 31, 2010, Chesapeake had long-term indebtedness of approximately $12.2 billion, with $1.8 billion of outstanding borrowings drawn under its $3.5 billion revolving credit facility and $37 million of outstanding borrowings drawn under its $250 million midstream revolving credit facility. 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 debt ratings for its senior notes are currently below investment grade, with ratings of Ba3 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

 

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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.

Our general partner may guarantee, or pledge any or all of its assets (other than its general partner interest, except as permitted by the partnership agreement) to secure, the indebtedness of any of its affiliates. If our general partner were required to honor its guarantee or if lenders foreclosed on our general partner’s assets, the ability of our general partner to manage our business might be adversely affected. If our general partner were unable to meet any obligations to such lenders, it might be required to file for bankruptcy, which would cause our dissolution under our partnership agreement and which might have other adverse effects.

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 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 region; 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,

 

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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.

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

 

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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 and electricity 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 currently 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. 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 by 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.

 

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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.

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.

 

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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.

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:

 

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

 

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

 

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

 

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the assumption of unknown liabilities;

 

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limitations on rights to indemnity from the seller;

 

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mistaken assumptions about the overall costs of equity or debt;

 

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

 

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unforeseen difficulties operating in new geographic areas; and

 

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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.

 

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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 may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it held in Chesapeake Midstream Ventures as of the closing of this offering. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement—Business Opportunities.”

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:

 

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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;

 

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inadvertent damage from construction, farm and utility equipment;

 

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

 

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other hazards.

 

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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.

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:

 

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incur additional debt or issue guarantees;

 

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•

incur or permit certain liens to exist;

 

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make certain investments, acquisitions or other restricted payments;

 

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modify certain material agreements;

 

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dispose of assets;

 

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engage in certain types of transactions with affiliates;

 

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

 

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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.

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:

 

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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;

 

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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;

 

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

 

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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.

 

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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 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 our Barnett Shale region in north-central Texas and our Mid-Continent region in Oklahoma, Texas, Arkansas 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. The location of the 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.

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. The U.S. Environmental Protection Agency, or the EPA, has commenced a study of the potential environmental impacts of hydraulic fracturing activities. At the same time, 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.

 

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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 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.

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

 

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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 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 the 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, are not subject to FERC jurisdiction. 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.

Moreover, FERC regulation affects our gathering and compression business generally. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on open

 

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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.

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.

If the services 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 and any additional services we may request pursuant to the services agreement. The initial term of the provision of general and administrative services by Chesapeake under the services 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 the services 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.

 

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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 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.

 

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•

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.”

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

 

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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;

 

•

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.

 

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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.

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

 

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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 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 direct transferees and their indirect transferees approved by our general partner and persons who acquired such units with the prior approval 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. 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.

 

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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 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.”

 

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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. 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 (the “Delaware 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;

 

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•

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

 

•

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

 

•

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. A portion of these costs are not subject to the volumetric-based cap in the services agreement applicable to general and administrative expenses for which we will reimburse 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, 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

 

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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 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.

 

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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 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

 

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the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Vinson & Elkins L.L.P. has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. 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. Vinson & Elkins L.L.P. has not rendered an opinion with respect to whether our method for depreciating Section 743 adjustments is sustainable in certain cases.

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 technically 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. For purposes

 

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of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical 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. A technical termination 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 technical termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs. 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, 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. Vinson & Elkins L.L.P. 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 all of the $             million of outstanding borrowings under our revolving credit facility and to reserve a substantial majority of the remaining $             million to fund expansion capital expenditures. Any amounts not used to fund expansion capital expenditures will be used for general partnership purposes, including acquisitions. The net proceeds from any exercise of the underwriters’ option to purchase additional common units will be distributed to GIP. Please read “Underwriting.”

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.

As of May 14, 2010, we had $123 million of borrowings outstanding under our revolving credit facility with a weighted average interest rate of 4.85%. Our revolving credit facility matures on September 30, 2012. Borrowings under our revolving credit facility have been used primarily to fund portions of $75 million distributions to each of Chesapeake and GIP and for working capital purposes.

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 substantially all of the underwriters 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 Successor as of March 31, 2010; and

 

•

our pro forma capitalization as of March 31, 2010, giving effect to the pro forma adjustments described in our unaudited pro forma financial data included elsewhere in this prospectus, including adjustments for our receipt of estimated net proceeds of $             million from the issuance and sale of common units in this offering.

We derived this table from, and it should be read in conjunction with and is qualified in its entirety by reference to, the consolidated historical financial statements and unaudited pro forma 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 March 31, 2010
		Successor Historical			Partnership Pro Forma(1)
		(In thousands)
Cash and cash equivalents		$	15,507		$	253,319
Revolving credit facility		$	—		$	—
Total equity:
Members’ net equity			1,803,519			2,041,331
Common units—public(2)(3)			—
Common units—Chesapeake			—
Common units—GIP			—
Subordinated units—Chesapeake			—
Subordinated units—GIP			—
General partner units			—
Total equity			1,803,519			2,041,331
Total capitalization		$	1,803,519		$	2,041,331

 

(1)

On a pro forma basis, as of March 31, 2010, 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. Pro forma capitalization also reflects a $150 million cash distribution to members on May 4, 2010 with $15.5 million of cash on hand and the proceeds of $134.5 million of borrowings under our revolving credit facility, which will be repaid at the closing of the offering.

(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 March 31, 2010, after giving effect to the offering of common units and the application of the related net proceeds, our net tangible book value was $            , 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. Because the total number of units outstanding following this offering will not change as a result of any exercise by the underwriters of their option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in the offering due to any such exercise of the option to purchase additional common units.

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 March 31, 2010, 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.

 

•

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

 

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•

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.

 

•

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 this offering equals the operating surplus from the closing of this 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. We do not anticipate that we will make any distributions from capital surplus.

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 September 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. 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.”

If the underwriters do not exercise their option to purchase additional common units, we will issue              common units to GIP at the expiration of the option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be sold to the public, and any of the          units not purchased by the underwriters pursuant to the option will be issued to GIP as part of our formation transactions. Accordingly, the exercise of the underwriters’ option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read “Underwriting.”

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.

 

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The table below sets forth the assumed number of outstanding common, 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).

 

		Minimum Quarterly Distributions
		Number of Units		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 September 30, 2010 based on the actual length of the period.

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 twelve months ending June 30, 2011. 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, 2009

 

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and the twelve months ended March 31, 2010, 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 for the twelve months ending June 30, 2011.

Unaudited Pro Forma Available Cash for the Year Ended December 31, 2009 and the Twelve Months Ended March 31, 2010

If we had completed the transactions contemplated in this prospectus on January 1, 2009, pro forma available cash generated for the year ended December 31, 2009 would have been approximately $147.8 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 April 1, 2009, our pro forma available cash generated for the twelve months ended March 31, 2010 would have been approximately $159.8 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 ($             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—Services Agreement.”

Our pro forma financial data does not give effect, prior to October 1, 2009, to our 20-year gas gathering agreement with Chesapeake and the other transaction documents that were originally entered into on September 30, 2009, in connection with the formation of Successor. 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, 2009 and for the twelve months ended March 31, 2010, 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. 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, 2009				Twelve Months Ended March 31, 2010
		(In millions)
Net Income:		$	55.1			$	60.3
Add:
Depreciation and amortization expense			73.2				79.3
Interest expense(1)			1.7				2.5
Income tax expense (benefit)			—				—
Impairment of property, plant and equipment and other assets			90.2				90.2
(Gain) loss on sale of assets			0.1				—
Adjusted EBITDA(2)		$	220.3			$	232.3
Less:
Pro forma cash interest expense(1)			2.5				2.5
Estimated maintenance capital expenditures(3)			70.0				70.0
Pro Forma Available Cash		$	147.8			$	159.8
Pro Forma Cash Distributions
Distributions per unit		$				$
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		$				$
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, 2009 and the twelve months ended March 31, 2010, our total capital expenditures were $373 million and $238 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 $70 million of these capital expenditures were maintenance capital expenditures for each of 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 and net proceeds from this offering. 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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Estimated Adjusted EBITDA for Twelve Months Ending June 30, 2011

In order to fund the aggregate minimum quarterly distribution on all units for the twelve months ending June 30, 2011 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 twelve months ending June 30, 2011. 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 twelve months ending June 30, 2011. 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 twelve months ending June 30, 2011. 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 June 30, 2011. 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 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 twelve months ending June 30, 2011. 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 June 30, 2011
		(In millions)
Revenues		$	480.9
Operating Expenses
Operating expenses			149.4
General and administrative			31.7
Depreciation and amortization expense			93.9
Total Operating Expenses			275.0
Operating Income			205.9
Interest expense			2.5
Net Income			203.4
Adjustments to reconcile net income to estimated Adjusted EBITDA:
Add:
Depreciation and amortization expense			93.9
Interest expense			2.5
Estimated Adjusted EBITDA(1)			299.8
Adjustments to reconcile estimated Adjusted EBITDA to estimated cash available for distribution:
Less:
Cash interest expense			2.5
Estimated expansion capital expenditures			223.5
Estimated maintenance capital expenditures			70.0
Add:
Cash on hand to fund expansion capital expenditures(2)			223.5
Estimated Cash Available for Distribution		$	227.3
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 annualized minimum quarterly 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.”

(2)	Includes approximately $             million of proceeds from this offering. Please read “—Assumptions and Considerations—Financing—Cash.”

 

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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 June 30, 2011.

General Considerations

 

•

As discussed further below, substantially all of our revenues and a significant portion of our expenses will be determined by contractual arrangements that 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

 

•

the services 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 June 30, 2011.

 

•

Although actual throughput will influence whether the amount of cash available for distribution for the twelve months ending June 30, 2011 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 $14 million, or 3%, decline in revenue. 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 $481 million for the twelve months ending June 30, 2011, as compared to pro forma revenues of $383 million and $390 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, 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 77% 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 615 Bcf of natural gas, or 1.7 Bcf per day, for the twelve months ending June 30, 2011 as compared to 566 Bcf, or 1.5 Bcf per day, for the year ended December 31, 2009 (a 9% increase) and 570 Bcf, or 1.6 Bcf per day, for the twelve months ended March 31, 2010 (an 8% increase). This significant expected increase in volumes in the forecast period is primarily based on our expectation that Chesapeake will significantly increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total relative to average fourth quarter 2009 levels by the end of 2010. Chesapeake’s average operated rig count in our Barnett Shale region in the first quarter of 2010 was 23 as compared to 18 for the fourth quarter of 2009, an increase of approximately 28%. We estimate that our Barnett Shale gathering systems will gather 396 Bcf of natural gas, or 1.1 Bcf per day, for the twelve months ending June 30,

 

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2011, an 18% increase as compared to 336 Bcf of natural gas, or 0.9 Bcf per day, for the year ended December 31, 2009 and a 15% increase as compared to 343 Bcf of natural gas, or 0.9 Bcf per day, for the twelve months ended March 31, 2010. In addition to volumes from newly drilled wells, we expect to continue to gather gas from approximately 4,000 currently connected natural gas wells, comprising approximately 70% of our total volume projection for the twelve months ending June 30, 2011.

 

•

Fees. We estimate that we will receive an average fee of $0.73 per Mcf for the twelve months ending June 30, 2011 as compared to $0.66 per Mcf and $0.67 per Mcf for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. Inclusive of minimum volume commitment payments (as described below), we estimate that we will receive revenue of $0.78 per Mcf for the twelve months ending June 30, 2011, as compared to $0.68 per Mcf and $0.68 per Mcf for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. Our contracted fees are projected to increase in 2010 as a result of increased fees effective for 2010 under our gas gathering agreements with Chesapeake and Total compared to fees effective for a significant portion of 2009 under our prior contract with Chesapeake. We also expect a higher growth rate in our higher-fee Barnett Shale volumes relative to our Mid-Continent volumes during the forecast period. Each of our new gas gathering agreements with Chesapeake and Total also contains an embedded annual fee escalator pursuant to which our fees are escalated effective as of January 1 of each year, with the next such escalation occurring January 1, 2011. Annual fee escalation occurs automatically under each of our gas gathering agreements with Chesapeake and Total without regard to any fee redetermination that may occur for a given period as discussed below.

 

•

Minimum Volume Commitment Payment. In our Barnett Shale region, our gas gathering agreements with Chesapeake and Total provide for prorated minimum volume commitments in the aggregate of approximately 418 Bcf, or approximately 1.1 Bcf per day, for the twelve months ending June 30, 2011. The prorated minimum volume commitments of 418 Bcf for the twelve months ending June 30, 2011 include approximately 20 Bcf of committed volumes that have been carried forward to the 2010 calendar year from the 2009 calendar year pursuant to a one-time allowance under our gas gathering agreements to carry forward up to 10% of the minimum volume commitments for the 2009 calendar year. 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 for the year in which the shortfall occurred. Our forecast assumes that we recognize revenue of $34 million during the twelve months ending June 30, 2011 as a result of projected volumes being less than the minimum volume commitments. Of this $34 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 for the twelve months ending June 30, 2011 are based on our current expectation that no fee redetermination will be undertaken in 2010, and that the maximum allowable increase will occur on January 1, 2011, as a result of capital investment expansion opportunities in our Mid-Continent region. Although our gas gathering agreements provide for a fee redetermination within our Barnett Shale region, such a redetermination cannot occur 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 $149 million for the twelve months ending June 30, 2011 as compared to the pro forma operating expenses of $142 million and $134 million for the year ended December 31,

 

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2009 and the twelve months ended March 31, 2010, respectively. This results in an estimated $7 million, or 5%, increase and a $15 million, or 11%, increase in operating expense for the forecast period relative to the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. The increased throughput projected in our Barnett Shale and Mid-Continent regions is expected to increase operating expenses by 9% and 8% relative to the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively, and we expect increases related to the installation of additional compression facilities in our Barnett Shale region. These increases will be partially offset by reductions in labor costs associated with operating efficiencies and other operating expenses. 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 31% and 39% of our operating expenses, respectively. Additionally, we will reimburse Chesapeake for its provision of certain engineering and operations services and any additional services we may request from Chesapeake pursuant to the services agreement. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services Agreement.”

General and Administrative Expenses

Our general and administrative expense will primarily consist of direct general and administrative expenses incurred by us and payments we make to Chesapeake in exchange for the provision of general and administrative services, including a portion of the $2 million of expenses we expect to incur as a result of becoming a publicly traded partnership. Under the services 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. The cap contained in the services agreement does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services 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 June 30, 2011 as compared to the pro forma general and administrative expenses of $21 million and $24 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. Of these $11 million and $8 million increases, we attribute approximately $2 million to the establishment of our dedicated management and operating team and $9 million and $6 million, respectively, to the growth in our general and administrative headcount consistent with the growth in our business. As noted under “Management,” our executive officers were appointed to our general partner in January 2010 when our general partner was formed. Please read “Management—Employment Agreements.” Therefore, their compensation is not reflected in our historical costs. These general and administrative 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 and increased headcount expenses). Of the $21 million and $24 million of general and administrative expenses for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively, $16 million and $17 million, respectively, were reimbursements to Chesapeake pursuant to the services agreement for general and administrative services. Included in our estimate for the forecast period is an assumed $19 million general and administrative expense reimbursement to Chesapeake under the services agreement, which has been estimated by applying the unadjusted cap of $0.03 per Mcf.

 

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Depreciation and Amortization Expense

We estimate that depreciation and amortization expense for the twelve months ending June 30, 2011 will be $94 million as compared to $73 million and $79 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, 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 June 30, 2011 will be $293 million as compared to the pro forma capital expenditures of $373 million and $238 million for the year ended December 31, 2009 and the twelve months ended March 31, 2010, respectively. The construction of additional gathering assets in our Barnett Shale region, which we estimate will comprise 71% of our growth capital expenditures during the twelve months ending June 30, 2011, is a multi-year project that requires the construction of a large base of infrastructure that will serve as the foundation for future asset construction. A significant portion of this base infrastructure was constructed and installed between 2006 and 2009, and, accordingly, we anticipate that investment in the construction of our gathering assets in our Barnett Shale region will require a less substantial investment in the forecast period as compared to previous periods.

 

•

Maintenance Capital Expenditures. Historically, we did not make a distinction between maintenance and expansion capital expenditures. Our estimate of $70 million for maintenance capital expenditures for the twelve months ending June 30, 2011 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 June 30, 2011 will total $223 million. Approximately 71% of these expenditures relate to expected activity in our Barnett Shale region, where Chesapeake has indicated that it will significantly increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total relative to average fourth quarter 2009 levels by the end of 2010. 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 as well as the Permian Basin.

Financing

 

•

Cash. At the closing of this offering and after using a portion of the net proceeds of this offering to repay approximately $     million of 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 approximately $     million, which we believe will be sufficient to fund our anticipated expansion capital expenditures during the forecast period. Although this portion of the net proceeds used to fund anticipated expansion capital expenditures is a nonrecurring source of funds, we expect that our other future sources of liquidity, including cash flow from operations and available borrowing capacity under our revolving credit facility, will be sufficient to fund future capital expenditures.

 

•

Indebtedness. For purposes of our forecast for the twelve months ending June 30, 2011, we have assumed that the closing of this offering takes place on July 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.

 

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•

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 June 30, 2011 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 June 30, 2011 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 September 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 September 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 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 from sources other than additional working capital borrowings.

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. 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.

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

 

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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 (including incremental distributions on incentive distribution rights) to finance all or a portion of the construction, acquisition or improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of 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 and 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; less

 

•

any loss realized on disposition of an investment capital expenditure.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $             million that will enable us, if we choose, to distribute as operating surplus 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

 

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distributions on equity interests in 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 that we receive from non-operating sources.

The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing 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 be excluded from operating expenditures 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 and its affiliates, payments made in the ordinary course of business 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 penultimate 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 employee benefit 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 assets sold in the ordinary course of business or as part of normal retirement or replacement of assets.

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 this offering equals the operating surplus from the closing of this 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.

 

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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 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

Estimated maintenance capital expenditures reduce operating surplus, but expansion capital expenditures, actual maintenance capital expenditures and investment capital expenditures do not. Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity or operating income. We expect that a primary component of maintenance capital expenditures will be well connection expenditures required to replace expected reductions in natural gas gathering volumes handled by our facilities. Other components of maintenance capital expenditures will 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 (including incremental distributions on incentive distribution rights) to finance all or any portion of the construction or development of a replacement 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 and 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 (with the concurrence of the conflicts committee of our board of directors) 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.

 

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Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long term. 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 operating income. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such capital improvement in respect of the period that commences 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 improvement commences commercial service and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

Investment capital expenditures 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.

As described below, neither investment capital expenditures nor expansion capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred 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 are also not subtracted from operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

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

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.

 

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Subordination Period. Except as described below, the subordination period will begin on the closing date of this offering and expire on 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 the minimum quarterly distribution on all of the outstanding common, subordinated and general partner units during those periods on a fully diluted weighted average basis; 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 all 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 Upon Removal of the General Partner. In addition, if the unitholders remove our general partner other than for cause:

 

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and

 

•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

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.

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

 

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•

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; plus

 

•

any net decrease made in subsequent periods in cash reserves for operating expenditures initially established with respect to such period to the extent such decrease results in a reduction of adjusted operating surplus in subsequent periods pursuant to the third bullet point above.

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. With respect to a quarter in which a shortfall amount is actually paid, adjusted operating surplus shall be reduced by an amount equal to the amount of quarterly shortfall payment estimates previously added by the general partner to adjusted operating surplus with respect to such minimum volume commitment period.

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 interests.

 

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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 interests.

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 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.

 

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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.

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 $

—

$

$

$

$

$

$

 

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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 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.

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

 

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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 per unit amount of any outstanding arrearages in payment of the minimum quarterly distribution.

For example, if a two-for-one split of the 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. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the 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.

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,

 

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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 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;

 

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•

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 Successor and pro forma financial and operating data for Chesapeake Midstream Partners, L.P. for the periods and as of the dates presented. On September 30, 2009, Chesapeake and GIP formed Successor in a joint venture transaction (the “JV Transaction”) to own and operate 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. Our Predecessor retained a 50% interest in Successor and continues to operate midstream assets outside of Successor. In connection with this offering, Chesapeake and GIP will contribute to us their membership interests in Successor. Accordingly, the selected consolidated historical financial and operating data presented below are presented for two periods, Predecessor and Successor, which relate to the accounting periods for our Predecessor preceding the JV Transaction and for Successor following the JV Transaction. The Predecessor and Successor periods have been separated by a vertical line to highlight the fact that the financial and operating data for the periods presented relate to different entities. Since our operations 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.

The selected consolidated historical balance sheet data as of December 31, 2008 and December 31, 2009 and selected consolidated historical statement of income and cash flow data for the years ended December 31, 2007 and 2008, the nine months ended September 30, 2009 and the three months ended December 31, 2009 presented below are derived from the audited historical consolidated financial statements of our Predecessor and Successor included elsewhere in this prospectus. Our Predecessor’s selected consolidated historical balance sheet data as of December 31, 2005, 2006 and 2007 and selected consolidated historical statement of income and statement of cash flow data for the years ended December 31, 2005 and 2006 are derived from audited historical consolidated financial statements of our Predecessor not included in this prospectus. The selected consolidated historical balance sheet data of Successor as of March 31, 2010 and selected consolidated historical statements of income and cash flow data for the three months ended March 31, 2010 are derived from the unaudited historical consolidated statements of Successor included elsewhere in this prospectus.

Our selected pro forma statement of income data for the year ended December 31, 2009 and the three months ended March 31, 2010 and the selected pro forma balance sheet data as of March 31, 2010 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 March 31, 2010, in the case of the pro forma balance sheet, and as of January 1, 2009, in the case of the pro forma as adjusted statements of operations for the year ended December 31, 2009, and for the three months ended March 31, 2010. These transactions include:

 

•

the contribution by Chesapeake and GIP of their membership interests in Successor to us, which represents only a portion of the business of our Predecessor (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 financial data does not give effect, prior to October 1, 2009, to our 20-year gas gathering agreement with Chesapeake and the other transaction documents that were originally entered into on September 30, 2009, in

 

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connection with the formation of Successor. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates.”

The following table includes our Predecessor’s and Successor’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																						Successor								Partnership Pro  Forma
		Year Ended December 31,																Nine Months Ended September 30, 2009						Three Months Ended								Year Ended December  31, 2009			Three Months Ended March 31, 2010
		2005				2006				2007				2008										December 31, 2009				March 31, 2010
																												(unaudited)				(unaudited)
						(In thousands, except per unit and operating data)
Statement of Income Data:
Revenues(1)		$	65,014			$	100,590			$	191,931			$	332,783			$	358,921					$	107,377			$	95,386			$	383,095			$     95,386
Operating expenses			19,612				34,914				77,589				141,803				146,604						31,874				30,693				142,048			30,693
Depreciation and amortization expense			5,080				9,761				24,505				47,558				65,477						20,699				21,950				73,212			21,950
General and administrative expense			1,804				2,766				6,880				13,362				22,782						3,493				7,250				20,773			7,750
Impairment of property, plant and equipment and other assets(2)			—				—				—				30,000				90,207						—				—				90,207			—
(Gain) loss on sale of assets(3)			—				—				—				(5,541	)			44,566						34				(30	)			47			(30	)
Total operating expenses			26,496				47,441				108,974				227,182				369,636						56,100				59,863				326,287			60,363
Operating income (loss)			38,518				53,149				82,957				105,601				(10,715	)					51,277				35,523				56,808			35,023
Interest expense			—				—				—				1,871				347						619				611				1,721			431
Other expense (income)			—				—				—				(278	)			(29	)					(34	)			(2	)			(9)			(2	)
Income (loss) before income taxes			38,518				53,149				82,957				104,008				(11,033	)					50,692				34,914				55,096			34,594
Income tax expense (benefit)(4)			14,444				19,931				31,109				(61,287	)			6,341						—				—				—			—
Net income (loss)		$	24,074			$	33,218			$	51,848			$	165,295			$	(17,374	)					50,692			$	34,914			$	55,096			34,594
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		$	141,760			$	381,090			$	965,801			$	2,339,473			$	2,870,547					$	1,776,415			$	1,788,425							$ 1,788,425
Total assets			154,923				403,141				1,010,112				2,583,765				3,232,840						1,958,675				1,865,711							2,103,523
Revolving bank credit facility			—				—				—				460,000				12,173						44,100				—							—
Total equity			129,461				325,951				847,421				1,793,269				2,996,403						1,793,627				1,803,519							2,041,331
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	29,510			$	55,587			$	93,948			$	236,774			$	100,748					$	14,730			$	118,325
Investing activities			(67,128	)			(218,843	)			(563,564	)			(1,384,834	)			(690,994	)					(46,352	)			(39,398	)
Financing activities			37,620				163,272				469,622				1,230,059				664,268						31,590				(63,423	)
Other Data:
Adjusted EBITDA(5)						$	62,910			$	107,462			$	177,896			$	189,564					$	72,044			$	57,445			$	220,283			56,945
Capital expenditures							218,843				563,564				1,402,449				756,883						46,377				39,451							39,451
Operating Data:
Throughput, MMcf/d			512				588				1,018				1,585				2,108						1,550				1,530				1,550			1,530
Average rate per Mcf		$	0.35			$	0.47			$	0.52			$	0.58			$	0.62					$	0.75				0.69			$	0.68		$	0.69

 

(1)

In the event either Chesapeake or Total does not meet its minimum volume commitment to us in our Barnett Shale Region under our gas gathering agreements, as adjusted in certain instances, 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.” Should payments be due under the minimum volume commitment with respect to any year, we recognize the

 

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associated revenue in the fourth quarter of such year. Revenues and average revenue per Mcf of Successor for the three months ended December 31, 2009 includes the impact of $8.4 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. Excluding the impact of such minimum volume commitment payment, the average rate per Mcf would have been $0.69 per Mcf.

(2)

Our Predecessor recorded an $86.2 million impairment associated with certain Mid-Continent gathering systems that are not expected to have future cash flows in excess of the book value of the systems. These systems were subsequently contributed to Successor as of 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 a certain treating facility as a result of the facility’s location in an area of continued declining throughput and a reduction in the future expected throughput volumes by Chesapeake, based on its revised future development plans on the associated oil and gas properties that serve as the primary source of throughput volumes for the facility.

(3)	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.

(4)

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 by recording a $86.2 million income tax benefit in 2008 at the time the change in legal structure occurred. This benefit was partially offset by income tax expense of $24.9 million, resulting in a net income tax benefit of $61.3 million for the year ended December 31, 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.

(5)

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 (for periods ending on or before September 30, 2009) and of the successor to our Predecessor for financial accounting purposes, which we refer to as “Successor” (for periods ending after September 30, 2009). On September 30, 2009, Chesapeake and GIP formed Successor in a joint venture transaction (the “JV Transaction”) to own and operate 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. Our Predecessor retained a 50% interest in Successor and continues to operate midstream assets outside of Successor. In connection with this offering, Chesapeake and GIP will contribute to us their membership interests in Successor. 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 (represented by Successor) 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 and Successor.

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 approximately 1,700 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 2,800 miles of gathering pipelines, servicing approximately 4,000 natural gas wells. For the three months ended March 31, 2010, our assets gathered approximately 1.5 Bcf of natural gas per day, which we believe ranks 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

 

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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.

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., Our Predecessor and Successor

In September 2009, Chesapeake and GIP formed Successor in the JV Transaction 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 Successor to us by conveying a 100% membership interest in Chesapeake MLP Operating, L.L.C., which has owned all of our assets since September 2009. 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 (represented by Successor) constitute only a portion of the historical assets and operations of our Predecessor. In addition to the gathering systems owned by Successor to be contributed to us at the closing of this offering, our Predecessor owns and operates gathering systems in, among other areas, the five other major U.S. shale plays: the Haynesville and Bossier Shales in northwestern Louisiana and east Texas; the Fayetteville Shale in central Arkansas; the Marcellus Shale in Pennsylvania, West Virginia and New York; and the Eagle Ford Shale in south Texas.

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 Successor 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 the JV Transaction 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:

 

(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 to us, as adjusted in certain instances, 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 and electricity 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 based on then current natural gas and electricity 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 services agreement, Chesapeake has agreed to provide us with certain general and administrative services and any additional services we may request. We will reimburse Chesapeake for such general and administrative 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. The cap contained in the services agreement does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership (which we expect to initially be $2.0 million per year). Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services 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 substantially 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 three months ended March 31, 2010, Chesapeake and its working interest partners accounted for approximately 95% of the natural gas volumes on our gathering systems and 97% of our revenues.

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.

 

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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 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 and certain other items management believes affect the comparability of operating results.

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.

 

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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 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 $327 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 significantly increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total relative to average fourth quarter 2009 levels by the end of 2010.

 

•

Our Predecessor incurred impairments of property, plant and equipment and other assets of $30.0 million and $90.2 million for the year ended December 31, 2008 and the nine months ended September 30, 2009, respectively.

 

•

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 or Successor.

 

•

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 services 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—Services Agreement.” The cap contained in the services agreement does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur 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.

 

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•

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.

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.

 

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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. As of May 11, 2010, the EIA forecasted 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 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—Capital Structure and Financial Flexibility.”

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.

Results of Operations—Combined Overview

JV Transaction and Basis of Presentation

On September 30, 2009, Chesapeake and GIP formed Successor in the JV Transaction to own and operate 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

 

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partners. Our Predecessor retained a 50% interest in Successor and continues to operate midstream assets outside of Successor. In connection with this offering, Chesapeake and GIP will contribute to us their membership interests in Successor. Accordingly, the financial and operating data presented below are presented for two periods, Predecessor and Successor, which relate to the accounting periods for our Predecessor preceding the JV Transaction and for Successor following the JV Transaction. The Predecessor and Successor periods have been separated by a vertical line to highlight the fact that the financial and operating data for the periods presented relate to different entities. Our assets are represented by Successor.

We have prepared our discussion of the results of operations by comparing the results of operations of our Predecessor for the years ended December 31, 2007 and 2008. We have presented brief discussions of the factors that materially affected our Predecessor’s operating results for the nine months ended September 30, 2009 (the “Predecessor 2009 Period”) along with Successor’s operating results for the three months ended December 31, 2009 (the “Successor 2009 Period”) and three months ended March 31, 2010 (the “Successor 2010 Period”). A comparative discussion of the results of operations of these periods has not been provided due to the lack of a comparable operating period. The following table and discussion present a summary of Successor’s consolidated and our Predecessor’s consolidated results of operations for the periods described above:

 

		Predecessor Consolidated											Successor
		Year Ended December 31,							Nine Months Ended September 30, 2009				Three Months Ended
		2007			2008								December 31, 2009						March 31, 2010
																			(unaudited)
		(In thousands, except operating data)
Revenues(1)		$	191,931		$	332,783			$	358,921			$	107,377					$	95,386
Operating expenses			77,589			141,803				146,604				31,874						30,693
Depreciation and amortization expense			24,505			47,558				65,477				20,699						21,950
General and administrative expense			6,880			13,362				22,782				3,493						7,250
Impairment of property, plant and equipment and other assets			—			30,000				90,207				—						—
(Gain) loss on sale of assets			—			(5,541	)			44,566				34						(30	)
Total operating expenses			108,974			227,182				369,636				56,100						59,863
Operating income (loss)			82,957			105,601				(10,715	)			51,277						35,523
Interest expense			—			1,871				347				619						611
Other expense (income)			—			(278	)			(29	)			(34	)					(2	)
Income (loss) before income taxes			82,957			104,008				(11,033	)			50,692						34,914
Income tax expense (benefit)			31,109			(61,287	)			6,341				—						—
Net income (loss)		$	51,848		$	165,295			$	(17,374	)		$	50,692					$	34,914
Operating Data:
Throughput, MMcf/d			1,018			1,585				2,108				1,550						1,530
Average rate per Mcf		$	0.52		$	0.58			$	0.62			$	0.75					$	0.69

 

 

(1)

In the event either Chesapeake or Total does not meet its minimum volume commitment to us in our Barnett Shale Region under our gas gathering agreements, as adjusted in certain instances, 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.” Should payments be due under the minimum volume commitment with respect to any year, we recognize the associated revenue in the fourth quarter of such year. Revenues and average revenue per Mcf of Successor for the three months ended December 31, 2009 includes the impact of $8.4 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. Excluding the impact of such minimum volume commitment payment, the average rate per Mcf would have been $0.69 per Mcf.

 

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Successor—Three Months Ended March 31, 2010

Revenues. Successor’s revenues are primarily attributable to the amount of throughput on its gathering systems and the rates charged for gathering such throughput. Average daily throughput for the Barnett Shale and Mid-Continent regions was 1.5 Bcf per day for the Successor 2010 Period. Average rates were $0.69 per Mcf for the Successor 2010 Period.

The table below reflects Successor’s revenues and throughput by region for the Successor 2010 Period:

 

		Successor
		Three Months Ended March 31, 2010
		Revenues			Throughput (MMcf)
		(In thousands, except operating data)
Barnett Shale		$	71,600		88,118
Mid-Continent			23,786		49,588
		$	95,386		137,706

Operating Expenses. Operating expenses for the Barnett and Mid-Continent were $0.22 per Mcf for the Successor 2010 Period. The table below reflects Successor’s total operating expenses and operating expenses per Mcf of throughput by region for the Successor 2010 Period:

 

		Successor
		Three Months Ended March 31, 2010
		Operating Expenses			Expenses ($ per Mcf)
		(In thousands, except per Mcf data)
Barnett Shale		$	18,965		$	0.22
Mid-Continent			11,728			0.24
		$	30,693		$	0.22

Depreciation and Amortization Expense. Depreciation and amortization expense for the Successor 2010 Period was $22.0 million and primarily related to gathering systems.

General and Administrative Expense. During the Successor 2010 Period, general and administrative expenses were $7.3 million and were primarily attributable to the expansion of Successor’s senior management team and the ongoing expansion of general and administrative functions of Successor.

(Gain) Loss on Sale of Assets. There was a $30,000 gain on the sale of assets during the Successor 2010 Period related to the sale of certain other fixed assets.

Interest Expense. Interest expense for the Successor 2010 Period was $611,000, which was net of $323,000 of capitalized interest. The interest expense is related to borrowings under our revolving credit facility.

Income Tax Expense (Benefit). There was no income tax expense during the Successor 2010 Period. Successor and its subsidiaries are 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.

 

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Successor—Three Months Ended December 31, 2009

Revenues. Successor’s revenues are primarily attributable to the amount of throughput on its gathering systems and the rates charged for gathering such throughput. Revenues for the Successor 2009 Period include $8.4 million attributable to Chesapeake associated with the minimum volume commitment in our Barnett Shale region for 2009. In the event either Chesapeake or Total does not meet its minimum volume commitment to us in our Barnett Shale Region under our gas gathering agreements, as adjusted in certain instances, 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. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Gas Gathering Agreements.” Should payments be due under the minimum volume commitment with respect any year, we recognize the associated revenue in the fourth quarter of such year. Average daily throughput for the Barnett and Mid- Continent was 1.6 Bcf per day for the Successor 2009 Period. For the Successor 2009 Period, average revenue was $0.75 per Mcf and average rates were $0.69 per Mcf before revenue associated with the minimum volume commitment. The table below reflects Successor’s revenues and throughput by region for the Successor 2009 Period:

 

		Successor
		Three Months Ended December 31, 2009
		Revenues			Throughput (MMcf)
		(In thousands, except operating data)
Barnett Shale		$	80,880		88,246
Mid-Continent			26,497		54,326
		$	107,377		142,572

Operating Expenses. Operating expenses for the Barnett and Mid-Continent were $0.22 per Mcf for the Successor 2009 Period. The table below reflects Successor’s total operating expenses and operating expenses per Mcf of throughput by region for the Successor 2009 Period:

 

		Successor
		Three Months Ended December 31, 2009
		Operating Expenses			Expenses ($ per Mcf)
		(In thousands, except per Mcf data)
Barnett Shale		$	18,638		$	0.21
Mid-Continent			13,236			0.24
		$	31,874		$	0.22

Depreciation and Amortization Expense. Depreciation and amortization expense for the Successor 2009 Period was $20.7 million and primarily related to gathering systems.

General and Administrative Expense. During the Successor 2009 Period, general and administrative expenses were $3.5 million primarily attributable to costs allocated from Chesapeake related to centralized general and administrative services provided under our agreements with Chesapeake.

(Gain) Loss on Sale of Assets. There was a $34,000 loss on the sale of assets during the Successor 2009 Period related to the sale of certain other fixed assets.

 

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Interest Expense. Interest expense for the Successor 2009 Period was $619,000, which was net of $1.8 million of capitalized interest. The interest expense was related to borrowings under our revolving credit facility.

Income Tax Expense (Benefit). There was no income tax expense during the 2009 Successor Period. Successor and its subsidiaries are 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.

Predecessor—Nine Months Ended September 30, 2009

Revenues. Predecessor’s revenues were $358.9 million with total volumetric throughput of 575 Bcf. Average rates were $0.62 per Mcf for the Predecessor 2009 Period. The table below reflects our Predecessor’s revenues and throughput by region for the Predecessor 2009 Period:

 

		Predecessor
		Nine Months Ended September 30, 2009
		Revenues			Throughput (MMcf)
		(In thousands, except operating data)
Barnett Shale		$	201,217		248,073
Mid-Continent			76,388		177,563
Fayetteville Shale			52,314		78,782
Haynesville Shale			24,106		60,752
Appalachian Basin			4,896		10,189
		$	358,921		575,359

Operating Expenses. Operating expenses were $146.6 million for the Predecessor 2009 Period. The table below reflects our Predecessor’s total operating expenses and operating expenses per Mcf of throughput by region for the Predecessor 2009 Period:

 

		Predecessor
		Nine Months  Ended September 30, 2009
		Operating Expenses			Expenses ($ per  Mcf)
		(In thousands, except per unit data)
Barnett Shale		$	73,505		$	0.30
Mid-Continent			36,987			0.21
Fayetteville Shale			27,509			0.35
Haynesville Shale			5,784			0.10
Appalachian Basin			2,819			0.28
		$	146,604		$	0.25

Depreciation and Amortization Expense. Depreciation and amortization expense was $65.5 million for the Predecessor 2009 Period and was primarily related to gathering systems.

General and Administrative Expense. General and administrative expense was $22.8 million for the Predecessor 2009 Period. During this period, our Predecessor incurred approximately $3.3 million of charges associated with the completion of the joint venture with GIP.

 

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Impairment of Property, Plant and Equipment and Other Assets. Impairment of property, plant and equipment and other assets for the Predecessor 2009 Period was $90.2 million. Our Predecessor recorded an $86.2 million impairment associated with certain gathering systems located in the Mid-Continent region that were 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 (formerly known as Chesapeake Midstream Partners, 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.

(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 Predecessor 2009 Period.

Interest Expense. Interest expense for the Predecessor 2009 Period was $347,000, which is net of $6.5 million of capitalized interest. The interest expense was related to borrowings under our Predecessor’s revolving credit facility that was established in October of 2008.

Income Tax Expense (Benefit). Our Predecessor recorded income tax expense of $6.3 million for the Predecessor 2009 Period. This income tax expense was related to our Predecessor’s remaining taxable entity that was not contributed to us and was 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

 

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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 the result of the expansion of our Predecessor’s operations primarily in the Barnett Shale region. The increase was driven by more 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. 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 Mcf 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

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 2007.

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.

Impairment of Property, Plant and Equipment and Other Assets. Our Predecessor recognized a charge of $30 million associated with the impairment of a treating facility. The impairment was the result of the facility’s location in an area of declining production and a reduction in the future expected throughput volumes by Chesapeake, based on its revised future development plans on the associated oil and natural gas properties that serve as the primary source of throughput volume for the facility. The treating facility was subsequently contributed to Successor upon its formation.

(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.

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

Income Tax Expense (Benefit). Our Predecessor recorded an income tax benefit of $61.3 million in 2008 compared to income tax expense of $31.1 million in 2007. Historically, our Predecessor filed consolidated federal and state income tax 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, did not result in a provision for income taxes in the financial statements.

 

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As such, our Predecessor provided for the change in legal structure by recording a $86.2 million income tax benefit in 2008 at the time the change in legal structure occurred. This benefit was partially offset by income tax expense of $24.9 million, resulting in a net income tax benefit of $61.3 million for the year ended December 31, 2008. Accordingly, our Predecessor’s effective income tax rate for the year ended December 31, 2008 was (58.9)%.

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.

Successor’s Liquidity and Capital Resources

Historically, Successor’s sources of liquidity included cash generated from operations and borrowings under Successor’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 December 31, 2009 and March 31, 2010, Successor had working capital of $49.4 million and $3.6 million, respectively. Successor’s working capital decreased from December 31, 2009 to March 31, 2010 as a result of repayments on Successor’s revolving credit facility.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of Successor for the Successor 2009 Period and for the Successor 2010 Period were as follows:

 

		Successor
		Three Months Ended December 31, 2009				Three Months Ended March 31, 2010
		(In thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	14,730			$	118,325
Investing activities		$	(46,352	)		$	(39,398	)
Financing activities		$	31,590			$	(63,423	)

Operating Activities. Net cash provided by operating activities was $14.7 million for the Successor 2009 Period and $118.3 million for the Successor 2010 Period. These amounts were primarily attributable to cash flow from operations offset by changes in working capital.

Investing Activities. Net cash used in investing activities was $46.4 million for the Successor 2009 Period and $39.4 million for the Successor 2010 Period. These amounts were primarily attributable to capital expenditures related to the expansion of gathering systems.

Financing Activities. Net cash provided by financing activities was $31.6 million for the Successor 2009 Period. This amount was primarily attributable to the net receipt of proceeds from credit facility borrowings. Net cash used in financing activities was $63.4 million for the Successor 2010 Period, resulting from net payments made on the revolving credit facility and a $19.5 million distribution to a member.

Capital Expenditures. For the Successor 2009 Period and for the Successor 2010 Period, capital expenditures were $46 million and $39 million, respectively, and primarily associated with the continued build-out of gathering systems in its primary areas of operations.

 

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Sources of Liquidity

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 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 March 31, 2010, our consolidated leverage ratio was 0.03 to 1 and our interest coverage ratio was 21.14 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

 

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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, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels and reduce costs or increase revenues.

We have budgeted approximately $332.2 million in capital expenditures for the year ending December 31, 2010, of which $262.2 million represents expansion capital expenditures and $70 million represents maintenance capital expenditures. Our budgeted 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, 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 March 31, 2010:

 

Contractual Obligation (In thousands)		Total			Less than 1 Year			1-3 Years			3-5 Years			More than 5 Years
Long-term debt		$	—		$	—		$	—		$	—		$	—
Operating leases(1)			121,286			47,173			71,059			2,214			840
Asset retirement obligations			2,903			—			—			—			2,903

 

(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 services 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— Services Agreement.” The cap contained in the services agreement does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. We currently expect those expenses to be

 

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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 substantially 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 pursuant to the employee secondment agreement. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Employee Secondment Agreement.”

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 JV Transaction as well as higher accounts receivable generated from increased throughput resulting from completed expansion projects and increased inventory levels.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of our Predecessor for the years ended December 31, 2007 and 2008, and for the Predecessor 2009 Period were as follows:

 

		Predecessor
		Year Ended December 31,								January 1, 2009 through September 30, 2009
		2007				2008
		(In thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities		$	93,948			$	236,774			$	100,748
Investing activities		$	(563,564	)		$	(1,384,834	)		$	(690,994	)
Financing activities		$	469,622			$	1,230,059			$	664,268

Operating Activities. Net cash provided by operating activities decreased by $136.0 million, or 57%, for the Predecessor 2009 Period as compared to the year ended 2008. This decrease was primarily attributable to an increase in cash flow from operations offset by changes in working capital for the Predecessor 2009 Period and because of the shorter period. 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.

Investing Activities. Net cash used in investing activities decreased by $693.8 million, or 50%, for the Predecessor 2009 Period as compared to the year ended 2008. This decrease was primarily attributed to the continued maturing of the Barnett Shale region and the completion of certain major projects and because of the shorter period. Net cash used in investing activities increased by $821.3 million, or 146%, in 2008 as compared to 2007. This increase was 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 16, 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

 

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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 changes in equity.

Net cash provided by financing activities decreased by $565.8 million, or 46%, for the Predecessor 2009 Period as compared to the year ended 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 and because of the shorter period. 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.

Capital Expenditures. For the year ended December 31, 2008 and the Predecessor 2009 Period, 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.

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 estimated useful lives of assets, which impacts depreciation and assumptions regarding future net cash flows. Although we and our Predecessor believe these estimates are reasonable, actual results could differ from our estimates.

Depreciation

Depreciation associated with our property, plant and equipment and other assets 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

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 their carrying value may not be recoverable. The carrying value of a long-lived asset is not recoverable if it

 

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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.

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 debt ratings for its senior notes are below investment grade, and they 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 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.

 

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Recent Accounting Pronouncements

In March 2008, the Emerging Issues Task Force of the Financial Accounting Standards Board reached a final consensus on the two-class method of earnings per share related to master limited partnerships, or MLPs. Their conclusion affects how an MLP 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 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:

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.

 

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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 25% of Texas’ natural gas production in 2009 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.

Source: ALL Consulting 2009 (prepared for U.S. Department of Energy report)

As of December 31, 2009, more than 13,000 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 7.0 Tcf of natural gas since 1993. As of May 10, 2010, there were approximately 220 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 1,755 new permits issued during 2009. From January 2010 through April 2010, 778 drilling permits were issued in the area.

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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Source: Railroad Commission of Texas

The location of the 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 (excluding the Fayetteville shale), 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, approximately 90% of the drilling rigs operating as of May 14, 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 based on public data well counts for wells spud after November 1, 2005.

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

 

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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 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 approximately 1,700 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 2,800 miles of gathering pipelines, servicing approximately 4,000 natural gas wells. For the three months ended March 31, 2010, our assets gathered approximately 1.5 Bcf of natural gas per day, which we believe ranks 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 one of the largest natural gas producers in the U.S. by volume of natural gas produced based on the most recent publicly available quarterly data reported, the most active driller for natural gas in the U.S. by number of drilling rigs utilized based on information published in “RigData” and has built a significant unconventional resource base, including in the Barnett Shale and Mid-Continent areas served by our gathering systems, as well as in the Haynesville, Fayetteville, Marcellus, Bossier and Eagle Ford 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 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 upstream assets 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 sixth largest integrated oil and gas company in the world based on market capitalization calculated using the most recent publicly available quarterly data reported. Chesapeake expects to significantly increase its operated rig count in our Barnett Shale acreage dedication as a result of this joint venture relative to average fourth quarter 2009 levels by the end of 2010.

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 five other major U.S. shale plays: the Haynesville and Bossier Shales in northwestern Louisiana and east Texas; the Fayetteville Shale in central Arkansas; the Marcellus Shale in Pennsylvania, West Virginia and New York; and the Eagle Ford Shale in south Texas. Chesapeake’s expanding midstream asset base in these areas supports its significant acreage positions and consists of approximately 1,500 miles of gathering pipelines that gathered approximately 1.0 Bcf of natural gas per day as of and for the quarter ended March 31, 2010. Chesapeake’s remaining midstream businesses including those in the Haynesville, Fayetteville, Marcellus, Bossier and Eagle Ford 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 75% of our revenues from our gathering systems in our Barnett Shale region and approximately 25% of our revenues from our gathering systems in our Mid-Continent region for the quarter ended March 31, 2010. The following table summarizes our average daily throughput and our assets by region for the quarter ended March 31, 2010:

 

Region		Location (State(s))		Average Throughput (MMcf/d)		Approximate Length (Miles)		Approximate Number of Wells Serviced		Gas Compression (Horsepower)(1)
Barnett Shale		TX		979		700		1,726		133,015
Mid-Continent		TX, OK, KS, AR		551		2,100		2,303		85,504
Total				1,530		2,800		4,029		218,519

 

(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 25% of all natural gas produced in Texas in 2009. 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

 

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characterized by thicker natural gas bearing zones, resulting in higher initial production rates. We believe that within the Core 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 quarter ended March 31, 2010, our Barnett Shale region gathering volumes averaged 979 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) 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 quarter ended March 31, 2010, our Mid-Continent region gathering volumes averaged approximately 551 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 natural gas supply sources positioned for continued production

 

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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 high drilling success rates compared to most conventional resource plays, and Chesapeake is among the primary producers in these areas. Our gathering systems in these areas collectively accounted for 76% of our average daily throughput for the three months ended March 31, 2010. 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. Our extensive operations in these areas together with our relationship with Chesapeake, one of the largest natural gas producers and a significant leasehold owner in the U.S. in unconventional resource plays, position us to become a major natural gas gatherer from unconventional resource plays in the U.S.

 

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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 low incremental cost, primarily in the form of additional compression, relative to our significant investment to date. 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.

 

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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 that are designed to support a return on invested capital, and we plan to maintain our focus on providing midstream energy services on a fixed-fee basis 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.

 

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Grow Through Disciplined Development and Accretive Acquisitions. We plan to selectively pursue accretive acquisitions of developed midstream assets from Chesapeake, including through our rights of first offer under our omnibus agreement, 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.

 

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Our Competitive Strengths

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

 

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Well-Positioned Asset Base. Our gathering systems include extensive high-quality natural gas pipeline networks in our Barnett Shale region and high-growth unconventional resource plays in our Mid-Continent region, such as the Colony Granite Wash and Texas Panhandle Granite Wash. Chesapeake has increased production in these areas over the past year and they 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 25% of Texas’ natural gas production in 2009. 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 major gatherer of natural gas from unconventional resource plays.

 

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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 and our system scale positions us to attract additional volumes from other producers. 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.

 

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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 into 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.

 

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Relationship with Chesapeake. Our relationship with Chesapeake, one of the industry’s leaders in unconventional natural gas drilling and production with significant positions in the Haynesville, Fayetteville, Marcellus, Bossier and Eagle Ford shale plays in addition to its operations in our Barnett Shale and Mid-Continent regions, provides us with significant potential long-term growth

 

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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 of additional midstream assets within five miles of our acreage dedications.

 

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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 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.

 

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Capital Structure and Financial Flexibility. We believe that our capital structure following this offering 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 one of the largest natural gas producers in the U.S. by volume of natural gas produced based on the most recent publicly available quarterly data reported and is the most active driller for natural gas in the U.S. by number of drilling rigs utilized based on information published in “RigData.” As of March 31, 2010, Chesapeake owned interests in approximately 44,900 gross producing natural gas and oil wells, which produced approximately 2.6 Bcfe (net) per day for the three months ended March 31, 2010, 90% of which was natural gas. Chesapeake’s primary operations are focused on discovering and developing unconventional and conventional natural gas and oil fields onshore in the U.S., primarily in the “Big 6” shale plays: the Barnett Shale, the Haynesville Shale, the Fayetteville Shale, the Marcellus Shale, the Bossier Shale and the Eagle Ford Shale. Chesapeake has also vertically integrated its operations and owns substantial midstream, compression, drilling and oilfield service assets.

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

 

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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:

 

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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 to one of the largest natural gas producers in the U.S., by volume of natural gas produced based on the most recent quarterly data reported, 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 a significant leasehold position in the U.S. “Big 6” shale plays (6.8 million gross acres, of which less than 10% have been dedicated to us).

 

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Our Operating Areas Are Core Growth Areas for Chesapeake. Our gathering systems in our Barnett Shale and Mid-Continent regions represent significant focus areas for Chesapeake. Chesapeake’s upstream joint venture with Total, which covers approximately 400,000 gross acres in the Barnett Shale, provides for a drilling carry resulting in Total’s paying a significant portion of Chesapeake’s drilling cost in the play. This drilling carry motivates Chesapeake to increase its production, and thereby the throughput on our systems in our Barnett Shale region. Additionally, many of our gathering systems in the Colony Granite Wash and Texas Panhandle Granite Wash plays gather natural gas from wells that also produce significant quantities of oil and natural gas liquids. Chesapeake has recently announced a new strategic plan to increase its rig count and production from these areas.

 

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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 our 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, and assuming no exercise of the underwriters’ option to purchase additional common units, 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

 

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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, a renewable power generation company.

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.

Chesapeake—Total Joint Venture

On January 26, 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 upstream assets 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:

 

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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 significantly increase its average operated rig count in our Barnett Shale acreage dedication as a result of its upstream joint venture with Total relative to average fourth quarter 2009 levels by the end of 2010. We believe that this increase in drilling activity will result in additional volumes being transported through systems in our Barnett Shale region.

 

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Strong Additional Major Customer. By partnering with Total, the sixth largest integrated oil and natural gas company in the world based on market capitalization calculated using the most recent publicly available quarterly data reported, 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 our 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 our 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:

 

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Barnett Shale Region. Our gathering systems in our 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

 

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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 a combined 133,015 horsepower of compression.

 

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Mid-Continent Region. Our Mid-Continent gathering systems extend across portions of Oklahoma, Texas (excluding the Barnett Shale), Arkansas (excluding the Fayetteville Shale) and Kansas and are comprised of approximately 2,100 miles of gathering pipelines and treatment facilities with over 551 MMcf of daily throughput using a combined 85,504 horsepower of compression. 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 delivery to major intrastate and interstate pipelines. We service approximately 4,000 natural gas wells. Natural gas is transferred from the producer’s wellhead or gathering pipeline to our gathering systems at receipt points including individual wells as well as 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 quarter ended March 31, 2010 was 979 MMcf/d. 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 a combined 133,015 horsepower of compression.

Supply. Chesapeake believes it is the largest producer, the most active driller and largest leaseholder in the Core and Tier 1 areas of the Barnett Shale. As of March 31, 2010, Chesapeake has produced in excess of 600 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.

 

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Delivery Points. Our Barnett Shale gathering system is connected to the following downstream transportation pipelines:

 

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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;

 

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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

 

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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.

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 1,275 miles of pipeline. Our Anadarko Basin and Northwest Oklahoma region gathering systems had an average throughput for the three months ended March 31, 2010 of 309 MMcf/d. These systems are connected to 31 compressor stations providing a combined 44,515 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 contain significant amounts of NGLs and require 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 believes it 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 March 31, 2010, Chesapeake has produced in excess of 900 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 three months ended March 31, 2010, Chesapeake produced approximately 350 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 325 miles of pipeline across the Permian and Delaware Basins. Average throughput on our gathering systems for the three months ended March 31, 2010 was 97 MMcf/d. The systems have pipeline diameters ranging from 4 inches to 16 inches and are connected to 10 compressor stations providing a combined 14,955 horsepower of compression.

 

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Supply. Chesapeake believes it is the largest producer and largest leaseholder in areas served by our Permian Basin gathering systems. As of March 31, 2010, 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 intrastate 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.

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 three months ended March 31, 2010 was 145 MMcf/d. The systems have pipeline diameters ranging from 4 inches to 24 inches and are connected to 27  compressor stations providing a combined 26,034 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.

 

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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.

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 the Federal Energy Regulatory Commission, or FERC, under the Natural Gas Act. Although the 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, are not subject to FERC jurisdiction. 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.

Moreover, FERC regulation affects our gathering and compression business generally. 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.

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

 

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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.

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:

 

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requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;

 

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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

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requiring investigatory and remedial actions to limit pollution conditions caused by our operations or attributable to former operations; and

 

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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, 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

 

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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 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

 

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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.

Hydraulic Fracturing

Legislation has been introduced in the U.S. Congress 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, and the EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities. 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 approved by the U.S. House of Representatives in June 2009, 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. Similar bills are presently pending before the U.S. Senate. 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,

 

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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, in December 2009, the EPA determined 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 response to its endangerment finding, the EPA recently adopted two sets of rules regarding possible future regulation of GHG emissions under the Clean Air Act, one of which purports to 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 motor vehicle rule became effective in March 2010, but it does not require immediate reductions in GHG emissions. The stationary source rule was adopted in May 2010, but it does not become effective until January 2011 and is the subject of several pending lawsuits filed by industry groups. In addition, in September 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.

 

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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.

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 March 31, 2010, Successor and Chesapeake jointly employed approximately 230 people who will provide direct support to our operations. From and after the effective date of this offering, 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, which is jointly and equally owned by Chesapeake and GIP, is the sole member of our general partner and will have the right to appoint our general partner’s entire board of 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. Currently, we expect to have three independent directors, as defined under the independence standards established by the NYSE and the Exchange Act, at the closing of this offering.

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.

We have no minimum qualifications for director candidates. In general, however, Chesapeake and GIP will review and evaluate both incumbent and potential new directors in an effort to achieve diversity of skills and experience among our directors and in light of the following criteria:

 

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experience in business, government, education, technology or public interests;

 

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high-level managerial experience in large organizations;

 

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breadth of knowledge regarding our business or industry;

 

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specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;

 

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moral character and integrity;

 

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commitment to our unitholders’ interests;

 

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ability to provide insights and practical wisdom based on experience and expertise;

 

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ability to read and understand financial statements; and

 

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ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

Although we do not have a policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

 

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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.

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 services 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,” “—Services 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 services agreement, the employee secondment agreement or otherwise. Under the services 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

 

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after the closing of the offering. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services 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 substantially 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.”

Board Leadership Structure and Role in Risk Oversight

Although our chief executive officer currently does not serve as a member of the board of directors of our general partner, we currently have no policy prohibiting our current or any future chief executive officer from serving as a member of the board, including as its chairman. Members of the board of directors of our general partner are designated or elected by the sole member of our general partner, Chesapeake Midstream Ventures.

The management of enterprise-level risk may be defined as the process of identification, management and monitoring of events that present opportunities and risks with respect to the creation of value for our unitholders. The board has delegated to management the primary responsibility for enterprise-level risk management, while the board has retained responsibility for oversight of management in that regard. Management will offer an enterprise-level risk assessment to the board at least once every year.

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		51		Chief Executive Officer
Robert S. Purgason		54		Chief Operating Officer
David C. Shiels		45		Chief Financial Officer
Matthew C. Harris		49		Director
Aubrey K. McClendon		50		Director
Marcus C. Rowland		57		Director
William A. Woodburn		59		Director

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.

 

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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 nine 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. We believe that Mr. Harris’ extensive energy industry background, particularly his expertise in mergers and acquisitions, brings important experience and skill to the board.

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. We believe that Mr. McClendon’s extensive energy industry background and relationship with Chesapeake, particularly his leadership skills in serving as Chairman of the Board and Chief Executive Officer of Chesapeake and his instrumental role in the formulation and promotion of national and local initiatives that promote American natural gas as the best solution for our nation’s future energy needs, bring important experience and skill to the board.

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. We believe that Mr. Rowland’s extensive energy industry background, particularly his financial reporting and oversight expertise, brings important experience and skill to the board.

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 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

 

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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. We believe that Mr. Woodburn’s extensive energy industry background, particularly the leadership skills he developed while serving in several executive positions, brings important experience and skill to the board.

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 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 initial grant of the number of units having a grant date value of $50,000 upon initial appointment as a director of our general partner. The independent directors will also receive an annual grant, effective on the first business day of January of each year that they serve as a director, 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.

 

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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 it, together with its board of directors and officers, will make decisions on our behalf. Chesapeake has decision-making authority with respect to the total compensation, subject to the approval of our general partner’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 and management incentive compensation 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 services 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.

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:

 

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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;

 

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Chesapeake’s performance—including operational performance, with respect to production, reserves, operating costs, drilling results, risk management activities and asset acquisitions and financial

 

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performance, with respect to cash flow, net income, cost of capital, general and administrative costs and common stock price performance; and

 

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Intangibles—for example, leadership ability, demonstrated commitment to the organization, motivational skills, attitude and work ethic.

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 and future awards that may be made under our long-term incentive 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.

 

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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.

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:

 

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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;

 

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A lower annual stock usage rate reduces the dilutive effect of stock compensation to shareholders;

 

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The income statement impact of restricted stock is more predictable, and less volatile, than that of stock options; and

 

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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

 

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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 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 (other than approximately 150 employees covered by collective bargaining agreements). 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—Agreements with Affiliates—Shared Services Agreement” and “—Employee Secondment Agreement.”

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 expected, 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

 

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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 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

 

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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 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 have been 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.

 

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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 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 disinterested directors and the special committee of the board of directors of our general partner.

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 Equity Uplift 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,

 

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who perform services for us. The summary of the LTIP contained herein does not purport to be complete and is 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 with respect to phantom units 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 has approved unit award grants to each of Messrs.             , and              in connection with their initial appointment to the board. The units will be granted upon the closing of this offering and will have an aggregate value to each director of $50,000. The actual number of units awarded under these grants will be determined by dividing the $50,000 by the initial public offering price per unit. In addition, as of the first business day of January of each year, our general partner intends to approve an annual unit grant which will have a value to each director of $12,500. The actual number of units awarded under the annual grant will be determined by dividing $12,500 by the closing unit price on the date of grant.

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, cash equal to the fair market value of a common unit. Our general partner may make grants of restricted units 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. Our general partner 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 units and phantom units will vest automatically upon a change of control of us or our general partner.

Distributions made by us with respect to awards of phantom units may, in our general partner’s discretion, be subject to the same vesting requirements as the restricted units. Our general partner, 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 units 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.

As of the first business day of January following the closing of this offering, our general partner intends to approve annual restricted unit grants to each of Messrs.             , and             . The restricted units will be granted effective upon the first business day of January following the closing of this offering and annually thereafter while the director serves as a member of our general partner’s board 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 closing unit price per unit on the date of grant. 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 our general partner 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 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, 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 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 our general partner.

Relation of Compensation Policies and Practices to Risk Management

We expect our compensation arrangements to contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us. Please read “—Compensation Discussion and Analysis.”

 

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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, and assuming the underwriters do not exercise their option to purchase additional common units, 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, 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.

(5)

Global Infrastructure Investors, Limited (“Global Infrastructure Investors”) and Global Infrastructure Management, LLC (“Global Infrastructure Management”), each located at 12 East 49th Street, 38th 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.

 

GIP’s ownership in us will be reduced to the extent the underwriters exercise their option to purchase additional common units. Please read “Summary—The Offering” for a description of the underwriters’ option to purchase additional common units.

 

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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.

The following table sets forth, as of May 18, 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		899,951		—		899,951		*
Marcus C. Rowland		80,565		—		80,565		*
William A. Woodburn		—		—		—		*
All directors and executive officers as a group (seven persons)		990,780		—		990,780		*

 

*	Less than 1.0%

(1)	The address for all beneficial owners in this table is 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118.

(2)	As of May 18, 2010, there were 650,913,132 shares of Chesapeake Energy Corporation common stock issued and outstanding.

 

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

After this offering, and assuming no exercise of the underwriters’ option to purchase additional common units, 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;

 

•

our incentive distribution rights; and

 

•

GIP’s right to receive the net proceeds from any exercise of the underwriters’ option to purchase additional common units and any common units subject to such option which are not purchased by the underwriters.

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.

 

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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.”

 

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. Prior to making distributions, we will reimburse Chesapeake for its provision of certain general and administrative services and any additional services we may request from Chesapeake (including certain incremental costs and expenses we will incur as a result of being a publicly traded partnership which we expect to initially be approximately $2.0 million per year), each pursuant to the services 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. Other than the volumetric cap on general and administrative expenses included in the services agreement, our reimbursement obligations are uncapped. Please read “—Agreements with Affiliates—Services Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement” below. In addition, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf. Under our partnership agreement, our general partner determines in good faith the amount of these expenses.

 

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 Midstream Partners, 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.

 

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Omnibus Agreement

Upon the closing of this offering, we will enter into an omnibus agreement with Chesapeake Midstream Ventures and Chesapeake Midstream Holdings that will address the following matters:

 

•

Chesapeake’s obligation to provide us with certain rights relating to certain future midstream business opportunities; and

 

•

our right to indemnification for certain liabilities and our obligation to indemnify Chesapeake Midstream Ventures and affiliated parties for certain liabilities.

Business Opportunities. Pursuant to the omnibus agreement, Chesapeake Midstream Holdings will provide us, or cause Chesapeake Energy Corporation and its affiliates to 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 Chesapeake entity 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 Midstream Holdings 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 Energy Corporation and its affiliates, 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, 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. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 30 days of the delivery of our offer, our offer will be deemed to have been accepted by Chesapeake Midstream Holdings, and we will have the right to pursue such proximate area opportunity on the terms set forth in our offer. In the event that we decline to make an offer or Chesapeake Midstream Holdings validly 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 Energy Corporation or any of its affiliates 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 the applicable Chesapeake entity at no cost and without liability or is otherwise terminated, our omnibus agreement will require the applicable Chesapeake entity 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. Unless Chesapeake Midstream Holdings rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer will be deemed to have been accepted by Chesapeake Midstream Holdings, and the applicable Chesapeake entity will enter into an agreement with us for the provision of the services covered by our offer on the terms set forth therein. In the event that Chesapeake Midstream Holdings

 

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validly 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 Energy Corporation or any of its affiliates 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, the applicable Chesapeake entity 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 days, to make an offer to the applicable Chesapeake entity to enter into the monetization transaction. Unless the applicable Chesapeake entity rejects our offer by written notice to us within 60 days of the delivery of our offer, our offer will be deemed to have been accepted, and the applicable Chesapeake entity will enter into an agreement with us providing for the consummation of the monetization transaction on the terms set forth in our 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. In the event that the applicable Chesapeake entity validly 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 and its affiliates 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

 

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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.

Chesapeake’s obligations to provide us with the business opportunities outlined above may be terminated by Chesapeake at any time each of GIP and Chesapeake holds less than half of the ownership interest it held in Chesapeake Midstream Ventures as of the closing of this offering.

Indemnification. Pursuant to the omnibus agreement, we will be entitled to indemnification for certain liabilities, and we will be required to indemnify Chesapeake Midstream Ventures for certain liabilities.

Chesapeake Midstream Ventures’ indemnification obligations to us include the following:

 

•

Environmental. For a period of three years after the closing of this offering, Chesapeake Midstream Ventures will indemnify us for environmental losses by reason of, or arising out of, any violation, event, circumstance, action, omission or condition associated with the operation of our assets prior to the closing of this offering, including: (i) any violation of or cost to correct a violation of any environmental laws, (ii) any environmental activity to address a release of hazardous substances and (iii) the release of, or exposure of any person to, any hazardous substance; provided, however, that (x) the aggregate liability of Chesapeake Midstream Ventures for environmental losses shall not exceed $15.0 million in the aggregate and (y) Chesapeake Midstream Ventures will only be liable to provide indemnification for environmental losses to the extent that the aggregate dollar amount of losses suffered by us exceed $250,000. In no event will Chesapeake Midstream Ventures have any indemnification obligations under the omnibus agreement for any claim made as a result of additions to or modifications of current environmental laws enacted after the effective date of the omnibus agreement.

 

•

Title. For a period of three years after the closing of this offering, Chesapeake Midstream Ventures will indemnify us for losses relating to our failure to be the owner as of the closing of this offering of valid and indefeasible easement rights, leasehold and/or fee ownership interests in and to the lands on which our assets are located, and such failure renders us liable to a third party or unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering.

 

•

Governmental consents and permits. For a period of three years after the closing of this offering, Chesapeake Midstream Ventures will indemnify us for losses relating to our failure to have any consent or governmental permit necessary to allow (i) the transfer of any of our assets to us upon the closing of this offering or (ii) any of our assets to cross the roads, waterways, railroads and other areas upon which any our assets are located as of the closing of this offering, and any such failure specified in such clause (ii) renders us unable to use or operate our assets in substantially the same manner that our assets were used and operated immediately prior to the closing of this offering.

 

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Taxes. Until the first day after the expiration of any applicable statute of limitations, Chesapeake Midstream Ventures will indemnify us for losses in respect of or arising from all federal, state and local income tax liabilities attributable to the ownership or operation of our assets prior to the closing of this offering.

In no event will Chesapeake Midstream Ventures be obligated to indemnify us for any claims, losses or expenses or income taxes referred to above to the extent such claims, losses or expenses or income taxes were

 

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either (i) reserved for in our financial statements as of the effective date of the omnibus agreement or (ii) are recovered under available insurance coverage, from contractual rights or other recoveries against any third party. Under the omnibus agreement, we will agree to use commercially reasonable efforts to realize any applicable insurance proceeds and amounts recoverable under such contractual obligations.

We will agree to indemnify Chesapeake Midstream Ventures, and the officers, directors, employees, agents and representatives of Chesapeake Midstream Ventures from and against all losses to the extent that such losses are in respect of or arise from events and conditions associated with the operation of our assets and occurring on or after the closing of this offering, unless in any such case indemnification is of a type that would not be permitted under our partnership agreement.

Services Agreement

Concurrent with the closing of this offering, we, our general partner, Chesapeake MLP Operating, L.L.C., Chesapeake Midstream Ventures and certain affiliates of Chesapeake Energy Corporation will enter into an amended and restated services agreement that requires Chesapeake to provide general and administrative services and additional services to us in return for a reimbursement of certain of its expenses in connection therewith.

The table below sets forth an estimate of the general and administrative expenses for which we will be obligated to reimburse Chesapeake pursuant to the services agreement for the twelve months ending June 30, 2011.

 

		Estimate for the Twelve Months Ending June 30, 2011
		(In millions)
Reimbursement for general and administrative services (including a portion of certain incremental costs and expenses we will incur as a result of being a publicly traded partnership, which we expect to initially be approximately $2.0 million per year)		$	18.6

General and Administrative Services and Reimbursement. Under the services 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, contract management support and other required corporate services and functions requested by us. In return for such general and administrative services, our general partner has agreed to reimburse Chesapeake, based on agreed upon formulas pursuant to the services agreement, 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 services agreement does not apply to the additional services reimbursement described below. Additionally, the cap does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership.

Additional Services and Reimbursement. At our request, Chesapeake will also agree to provide us with certain additional services under the services agreement, including engineering, construction, procurement,

 

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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 services 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 has agreed to 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 twelve months ending June 30, 2011, we estimate that we will reimburse GIP approximately $0.5 million for these support services.

The term of the services agreement 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, on December 31, 2011, our general partner has the right to extend the term of the services agreement through June 30, 2012 regardless of any other party providing notice to terminate. In such a situation, the services agreement would automatically terminate on June 30, 2012.

Indemnification

Pursuant to the services agreement, certain affiliates of Chesapeake (the “Chesapeake Affiliates”) will agree to indemnify our general partner and its subsidiaries, Chesapeake MLP Operating, L.L.C. and us (collectively, the “Partnership Group”) from and against certain potential claims, losses and expenses attributable to (i) breaches by the Chesapeake Affiliates of the services agreement, (ii) acts or omissions by the Chesapeake Affiliates in providing services in breach of the standard of performance set forth in the services agreement and (iii) claims by a third party relating to (A) breaches by the Chesapeake Affiliates of the services agreement, or (B) the Chesapeake Affiliates’ gross negligence or willful misconduct.

Additionally, the Partnership Group will agree to indemnify the Chesapeake Affiliates from and against certain potential claims, losses and expenses attributable to (i) breaches by the Partnership Group of the services agreement or (ii) claims by a third party relating to (A) any acts or omissions of the Chesapeake Affiliates in connection with their performance of the services outlined in the services agreement, solely to the extent that (x) such acts or omissions were performed or omitted at the direction of our general partner, and without material deviation therefrom, and (y) such services were performed in accordance with the standard of performance set forth in the services agreement, or (B) the Partnership Group’s gross negligence or willful misconduct.

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 substantially 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 June 30, 2011, we anticipate that our general partner will reimburse Chesapeake approximately $35.4 million for the services rendered by such seconded employees during such period.

 

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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 Corporation in connection with Mr. Stice’s employment. Our general partner is generally expected, 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 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. Please read “Management—Employment Agreements—Agreement with J. Mike Stice, President and Chief Executive Officer” for a description of the costs, expenses and benefits afforded to Mr. Stice in connection with his employment agreement.

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

 

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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. We expect that we will generate substantially all of our estimated $481 million of revenues for the twelve months ending June 30, 2011 pursuant to these gas gathering agreements.

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 1.35 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 to us, as adjusted in certain instances, 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 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,

 

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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 and electricity 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 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

 

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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 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 estimate that we will incur compression expenses of $58.6 million for the twelve months ending June 30, 2011 pursuant to the gas compressor master rental and servicing agreement.

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.

 

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Inventory Purchase Agreement

We have entered into an inventory purchase agreement pursuant to which we have agreed beginning as of September 30, 2009 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. We estimate that we will have purchased approximately $34.8 million of inventory by June 30, 2011 pursuant to this inventory purchase agreement.

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 master rental and servicing agreement, the services agreement, 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 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.

 

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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 and certain of their affiliates certain demand and “piggyback” registration rights. Under the registration rights agreement, each of Chesapeake and GIP and certain of their affiliates will generally have the right to require us to file a registration statement for the public sale of all of the equity interests in the Partnership, including common and subordinated units and incentive distribution rights (collectively, “partnership securities”) owned by it. In addition, if we sell any partnership securities in a registered underwritten offering, each of Chesapeake and GIP and certain of their affiliates will have the right, subject to specified limitations, to include its partnership securities in that offering.

We will pay all expenses relating to any demand or piggyback registration, except for underwriters or brokers’ commission or discounts.

Review, Approval or Ratification of Transactions with Related Persons

We will adopt a Code of Business Conduct and Ethics that will set forth our policies for the review, approval and ratification of transactions with related persons. Under the Code of Business Conduct and Ethics, a director would be expected to bring to the attention of the chief executive officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict will be addressed in accordance with Chesapeake Midstream Venture’s and our general partner’s organizational documents and the provisions of our partnership agreement. The resolution may be determined by disinterested directors, the board and/or a “conflicts committee” meeting the definitional requirements for such a committee under our partnership agreement.

Upon our adoption of the Code of Business Conduct and Ethics, any executive officer of our general partner will be required to avoid conflicts of interest unless approved by the board of directors.

In the case of any sale of equity by us to an owner or affiliate of an owner of our general partner, we anticipate that our practice will be to obtain general approval of the board of directors for the transaction. Our general partner’s board may delegate authority to set the specific terms of such a sale of equity to a pricing committee.

 

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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:

 

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approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;

 

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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;

 

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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 under our partnership agreement 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 the services agreement, subject to the cap specified therein. Please read “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services Agreement,” “—Employee Secondment Agreement” and “—Shared Services Agreement.” 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, issuances 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 subordinated 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. The Delaware Act provides that, unless

 

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otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity, an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement.

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 is appointed, 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 becomes bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

•

gives the consents, waivers 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.

Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

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.

 

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Common units are securities and any transfers are subject 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 be reasonably likely to 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 and treating 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.

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.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

For a discussion of our general partner’s right to contribute capital to maintain its 2% general partner interest if we issue additional units, please read “—Issuance of Additional Securities.”

 

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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 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 our partnership agreement

Certain amendments may be made by our 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 June 30, 2020 in a manner that would cause a dissolution of our partnership. Please read “—Withdrawal or Removal of Our General Partner.”

 

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 June 30, 2020. Please read “—Transfer of General Partner Units.”

 

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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, the sale of all of the ownership interests in our general partner, the pledge, hypothecation, mortgage, encumbrance, grant of a lien, collateralization, or other grant of a security interest in the incentive distribution rights in favor a person providing bona-fide debt financing to such holder as security or collateral for such debt financing and the transfer of incentive distribution rights in connection with exercise of any remedy of such person in connection therewith, 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 June 30, 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.”

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 from our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner or to any person or group who acquires the units with the specific prior approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

•

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement) or the duties, obligations or liabilities among limited partners or of limited partners, or the rights or powers of, or restrictions on, the limited partners or us;

 

•

brought in a derivative manner on our behalf;

 

•

asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

•

asserting a claim arising pursuant to any provision of the Delaware Act; and

 

•

asserting a claim governed by the internal affairs doctrine

shall be exclusively brought in the Court of Chancery of the State of Delaware, regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

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

 

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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 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 members or limited partners for the obligations of a limited liability company or 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.

 

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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 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 in its sole discretion.

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.

 

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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 Advisers 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 in connection with the creation, authorization or issuance of additional partnership securities or the right to acquire partnership securities;

 

•

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

 

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•

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. Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. 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. For amendments of the type not requiring 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.

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 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. 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.

 

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Dissolution

We will continue as a limited partnership until dissolved 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 under Delaware law of any limited partner; and

 

•

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 (and to the extent not already so treated or taxed).

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, 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 June 30, 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 June 30, 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

 

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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 “—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 gives them the 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:

 

•

the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner; and

 

•

if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end.

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 and the incentive distribution rights of the departing general partner or its affiliates 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 all of its or its affiliates’ 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,

 

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our general partner may not transfer all or any of its general partner units to another person prior to June 30, 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, among other things, assume 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, the owners of our general partner may sell or transfer all or part their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Transfer of Incentive Distribution Rights

Our general partner or its affiliates or a subsequent holder may (i) transfer its incentive distribution rights to an affiliate of the holder (other than an individual) or 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 substantially all of such holder’s assets to that entity or (ii) pledge, hypothecate, mortgage, encumber, grant a lien, collateralize, or grant a security interest in the incentive distribution rights in favor of a person providing bona-fide debt financing to such holder as security or collateral for such debt financing and the transfer of incentive distribution rights in connection with exercise of any remedy of such person in connection therewith, without the prior approval of the unitholders. Prior to June 30, 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 June 30, 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. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. 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 in certain circumstances. Please read “—Meetings; Voting.”

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 beneficial owners thereof 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.

 

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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 an undesirable time or 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.”

Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to U.S. 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, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the nationality, citizenship or other related status of our member (and their owners, to the extent relevant); and

 

•

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Non-Taxpaying Assignees; Redemption

In the event any rates that we charge our customers become regulated by the Federal Energy Regulatory Commission, to avoid any adverse effect on the maximum applicable rates chargeable to customers by us, or in order to reverse an adverse determination that has occurred regarding such maximum rate, our partnership agreement provides our general partner the power to amend the agreement. If our general partner, with the advice of counsel, determines that our not being treated as an association taxable as a corporation or otherwise taxable as an entity for U.S. federal income tax purposes, coupled with the tax status (or lack of proof thereof) of one or more of our limited partners, has, or is reasonably likely to have, a material adverse effect on the maximum applicable rates chargeable to customers by us, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the U.S. federal income tax status of our member (and their owners, to the extent relevant); and

 

•

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the maximum applicable rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the U.S. federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding certain persons or groups 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.

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

 

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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 (at the time of transfer) transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, 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 manager, managing member, director, officer, employee, agent, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

•

any person who is or was serving as a manager, managing member, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

 

•

any person who controls our general partner or any departing general partner; 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 incur 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 be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

We will furnish each record holder with information reasonably required for federal and state 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 our general partner. We are obligated to pay all expenses incidental to the registration, excluding underwriting discounts and fees.

In connection with this offering, we will enter into a registration rights agreement with Chesapeake and GIP. Please read “—Certain Relationships and Related Party Transactions—Agreements with Affiliates—Registration Rights Agreement.” Please read “Units Eligible for Future Sale.”

Operating Agreement of Chesapeake MLP Operating, L.L.C.

In connection with the closing of this offering, Chesapeake and GIP will contribute their membership interests in Chesapeake MLP Operating, L.L.C., formerly known as Chesapeake Midstream Partners, L.L.C., to us. We will conduct all of our operations through Chesapeake MLP Operating, L.L.C. and its subsidiaries. Concurrent with the closing of this offering, the limited liability company agreement of Chesapeake MLP Operating, L.L.C. will be amended and restated to reflect its being our wholly owned subsidiary, among other things. Under the amended and restated limited liability company agreement, the management of Chesapeake MLP Operating, L.L.C. will be vested in us. As the sole member, we will have the authority to cause Chesapeake MLP Operating, L.L.C. to make distributions to us, among other things, as required.

 

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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.

Additionally, 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 generally have the right to require us to file a registration statement for the public sale of all of the partnership securities in the partnership owned by it. In addition, if we sell any partnership securities in a registered underwritten offering, each of Chesapeake and GIP will have the right, subject to specified limitations,

 

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to include its partnership securities in that offering. We will pay all expenses relating to any demand or piggyback registration, except for underwriters or brokers’ commission or discounts.

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 a 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 announced that it is actively 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.

The recently enacted Health Care and Education Reconciliation Act of 2010 will impose a 3.8% Medicare tax on certain investment income earned by individuals for taxable years beginning after December 31, 2012. For these purposes, investment income generally includes a unitholder’s allocable share of our income and any gain realized by a unitholder from a sale of units. The tax will be imposed on the lesser of (i) the unitholder’s net income from all investments, and (ii) the amount by which the unitholder’s adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly) or $200,000 (if the unitholder is unmarried).

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)

 

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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 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

 

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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 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

 

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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 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:

 

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a short sale;

 

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an offsetting notional principal contract; or

 

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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.

 

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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, however, the Department of the Treasury and the IRS issued proposed Treasury 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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. 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 technically 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 receiving 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 recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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.”

 

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We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the 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:

 

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the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

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whether the beneficial owner is:

 

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a person that is not a U.S. person;

 

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a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

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a tax-exempt entity;

 

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the amount and description of units held, acquired or transferred for the beneficial owner; and

 

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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 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

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for which there is, or was, “substantial authority”; or

 

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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:

 

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accuracy-related penalties with a broader scope, significantly narrower exceptions, and potentially greater amounts than described above at “—Accuracy-Related Penalties”;

 

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for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

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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, 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.

The personal tax consequences of an investment in us may vary among unitholders under the laws of pertinent jurisdictions and, therefore, 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

UBS Securities LLC, Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated are acting 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
UBS Securities LLC
Citigroup Global Markets Inc.
Morgan Stanley & Co. Incorporated
Merrill Lynch, Pierce, Fenner & Smith Incorporated
Barclays Capital Inc.
Credit Suisse Securities (USA) LLC
Goldman, Sachs & Co.
Wells Fargo Securities, LLC
BBVA Securities Inc.
BMO Capital Markets Corp.
Deutsche Bank Securities Inc.
Raymond James & Associates, Inc.
RBS Securities Inc.
Scotia Capital (USA) Inc.
BNP Paribas Securities Corp.
Comerica Securities, Inc.
Credit Agricole Securities (USA) Inc.
ING Financial Markets LLC
Mitsubishi UFJ Securities (USA), Inc.
Piper Jaffray & Co.
RBC Capital Markets Corporation
SunTrust Robinson Humphrey, Inc.
TD Securities (USA) LLC
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

 

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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.

If the underwriters do not exercise their option to purchase additional common units, we will issue              common units to GIP at the expiration of the 30-day option period. If and to the extent the underwriters exercise their option to purchase additional common units, the number of units purchased by the underwriters pursuant to such exercise will be sold to the public, and any of the          units not purchased by the underwriters pursuant to the option will be issued to GIP as part of our formation transactions. Accordingly, whether or not the underwriters exercise their option to purchase additional common units will not affect the total number of units outstanding at the end of the 30-day option period or the amount of cash needed to pay the minimum quarterly distributions on all units.

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 UBS Securities LLC, 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.

UBS Securities LLC, 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 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 have applied to list our common units on the NYSE under the symbol “CHKM”. 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.

 

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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		$			$

We will pay a structuring fee equal to an aggregate of 0.75% of the gross proceeds from this offering to Citigroup Global Markets Inc. and Morgan Stanley & Co. Incorporated for the evaluation, analysis and structuring of our partnership.

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.

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

 

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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.

The underwriters have advised us that they do not intend to confirm sales to discretionary accounts that exceed 5% of the total number of common units offered by them.

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 UBS Securities LLC, Citigroup Global Markets Inc., Morgan Stanley & Co. Incorporated, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Goldman, Sachs & Co., Wells Fargo Securities, LLC, BBVA Securities Inc., BMO Capital Markets Corp., Deutsche Bank Securities Inc., Raymond James & Associates, Inc., RBS Securities Inc., Scotia Capital (USA) Inc., BNP Paribas Securities Corp., Comerica Securities, Inc., Credit Agricole Securities (USA) Inc., ING Financial Markets LLC, Mitsubishi UFJ Securities (USA), Inc., Piper Jaffray & Co., RBC Capital Markets Corporation, BBVA Securities Inc. and TD Securities (USA) LLC, 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., Morgan Stanley & Co. Incorporated, Credit Agricole Securities (USA) Inc., Deutsche Bank Securities Inc., RBS Securities Inc., Goldman, Sachs & Co. and TD Securities (USA) LLC and Credit Suisse Securities (USA) LLC are counterparties to Chesapeake’s multi-counterparty secured hedging facility, and Wells Fargo Securities, LLC acts as collateral agent under such facility. Affiliates of Morgan Stanley & Co. Incorporated, Deutsche Bank Securities Inc., RBS Securities Inc., Wells Fargo Securities, LLC and Goldman, Sachs & Co. are purchasers of volumetric production payments from Chesapeake. Affiliates of Citigroup Global Markets Inc. and RBS Securities Inc. are lenders under GIP’s credit facility. Affiliates of Barclays Capital Inc., BNP Paribas Securities Corp., SunTrust Robinson Humphrey, Inc., Morgan Stanley & Co. Incorporated, Credit Agricole Securities (USA) Inc., Deutsche Bank Securities Inc., Scotia Capital (USA) Inc., RBS Securities Inc., Wells Fargo Securities, LLC, Goldman, Sachs & Co. and RBC Capital Markets Corporation are lenders under Chesapeake’s revolving credit facility. In connection with providing financial advisory services to Chesapeake in connection with the formation of the joint venture between Chesapeake and GIP (which we refer to as our Predecessor), UBS Securities LLC received a right of first refusal with respect to participation in this offering and certain future financings, securities offerings and dispositions and acquisitions by us.

We, our general partner and certain of our affiliates 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.

 

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Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (“FSMA”) that is not a “recognised collective investment scheme” for the purposes of FSMA (“CIS”) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and are only directed at:

(i) if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) Order 2001, as amended (the “CIS Promotion Order”) or (b) high net worth companies and other persons falling with Article 22(2)(a) to (d) of the CIS Promotion Order; or

(ii) otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the “Financial Promotion Order”) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

(iii) in both cases (i) and (ii) to any other person to whom it may otherwise lawfully be made, (all such persons together being referred to as “relevant persons”). Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

 

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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 (i) Chesapeake Midstream Development, L.P. as of December 31, 2008, for the period of January 1, 2009 through September 30, 2009, and the years ended December 31, 2008 and 2007; and (ii) Chesapeake Midstream Partners, L.L.C. as of December 31, 2009 and for the period of October 1, 2009 through December 31, 2009 included in this prospectus have been so included in reliance on the reports, which contain explanatory paragraphs 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,” “plan,” “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 March 31, 2010		F-3
Unaudited pro forma statement of operations for the year ended December 31, 2009		F-4
Unaudited pro forma statement of operations for the three months ended March 31, 2010		F-5
Notes to unaudited pro forma financial data		F-6
CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. CONSOLIDATED FINANCIAL STATEMENTS:
Unaudited Condensed Consolidated balance sheets as of March 31, 2010 and December 31, 2009		F-8
Unaudited Condensed Consolidated statements of operations for the three months ended March  31, 2010 and March 31, 2009		F-9
Unaudited Condensed Consolidated statements of cash flows for the three months ended March  31, 2010 and March 31, 2009		F-10
Unaudited Condensed Consolidated statements of changes in equity for the three months ended March  31, 2010		F-11
Notes to unaudited consolidated financial statements		F-12
Reports of independent registered public accounting firm		F-17
Consolidated balance sheets as of December 31, 2009 and 2008		F-19
Consolidated statements of operations for the period of October 1, 2009 through December 31, 2009, the period of January 1, 2009 through September 30, 2009 and the years ended December 31, 2008 and 2007		F-20
Consolidated statements of changes in equity for the period of October 1, 2009 through December 31, 2009, the period of January 1, 2009 through September 30, 2009 and the years ended December 31, 2008 and 2007		F-21
Consolidated statements of cash flows for the period of October 1, 2009 through December 31, 2009, the period of January 1, 2009 through September 30, 2009 and the years ended December 31, 2008 and 2007		F-22
Notes to consolidated financial statements		F-23
CHESAPEAKE MIDSTREAM PARTNERS, L.P. FINANCIAL STATEMENT:
Report of independent registered public accounting firm		F-35
Balance sheet as of February 12, 2010		F-36
Note to financial statement		F-37
CHESAPEAKE MIDSTREAM GP, L.L.C. FINANCIAL STATEMENT:
Report of independent registered public accounting firm		F-38
Balance sheet as of February 12, 2010		F-39
Note to financial statement		F-40

 

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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 March 31, 2010, for the year ended December 31, 2009 and for the three months ended March 31, 2010, have been derived from the consolidated historical financial statements of Chesapeake Midstream Development, L.P. and its subsidiaries (Chesapeake Midstream Development or our Predecessor) and of Chesapeake Midstream Partners, L.L.C. and its subsidiaries (Chesapeake Midstream Partners or Successor) 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 financial statements of Chesapeake Midstream Partners and 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 consolidated historical financial statements of Chesapeake Midstream Partners and 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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CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA BALANCE SHEET

March 31, 2010

 

		Partnership Historical			Adjustments for Cash Distribution				Adjustments for the Offering				Partnership Pro Forma
		(In thousands)
Assets
Current assets:
Cash and cash equivalents		$	15,507		$	(15,507	)(b)		$	425,000	(c)		$	253,319
			—			—				(28,688	)(d)			—
			—			—				(8,500	)(e)			—
			—			—				(134,493	)(f)			—
Accounts receivable			45,436			—				—				45,436
Other current assets			1,969			—				—				1,969
Total current assets			62,912			(15,507	)			253,319				300,724
Property, plant and equipment, net			1,788,425			—				—				1,788,425
Other assets			14,374			—				—				14,374
Total assets		$	1,865,711		$	(15,507	)		$	253,319			$	2,103,523
Liabilities and Equity
Current liabilities:
Accounts payable		$	27,479		$	—			$	—			$	27,479
Accrued liabilities and other			31,810			—				—				31,810
Total current liabilities			59,289			—				—				59,289
Long-term liabilities:
Revolving bank credit facility			—			134,493	(b)			(134,493	)(f)			—
Other liabilities			2,903			—				—				2,903
Total long-term liabilities			2,903			134,493				(134,493	)			2,903
Commitments and contingencies
Equity:
Members’ equity			1,803,519			(150,000	)(b)			425,000	(c)			2,041,331
			—			—				(28,688	)(d)			—
			—			—				(8,500	)(e)			—
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			—			—				—				—
Total equity			1,803,519			(150,000	)			387,812				2,041,331
Total liabilities and equity		$	1,865,711		$	(15,507	)		$	253,319			$	2,103,523

See accompanying notes to unaudited pro forma financial data.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

UNAUDITED PRO FORMA STATEMENT OF OPERATIONS

Year Ended December 31, 2009

 

		Predecessor Historical											Successor Historical
		January  1, 2009 through September 30, 2009				Predecessor Retained Operations(a)				Partnership Pro Forma			October 1, 2009 through December 31, 2009				Adjustments for the Offering				Partnership Pro Forma as Adjusted
		(In thousands except per unit data)
Revenues		$	358,921			$	(83,203	)		$	275,718		$	107,377			$	—			$	383,095
Expenses:
Operating expenses			146,604				(36,430	)			110,174			31,874				—				142,048
Depreciation and amortization expense			65,477				(12,964	)			52,513			20,699				—				73,212
General and administrative expense			22,782				(7,502	)			15,280			3,493				2,000	(g)			20,773
Impairment of property, plant and equipment and other assets			90,207				—				90,207			—				—				90,207
(Gain) loss on sale of assets			44,566				(44,553	)			13			34				—				47
Total operating expenses			369,636				(101,449	)			268,187			56,100				2,000				326,287
Operating income (loss)			(10,715	)			18,246				7,531			51,277				(2,000	)			56,808
Interest expense			347				(126	)			221			619				(840	)(h)			1,721
			—				—				—			—				1,721	(i)			—
Other expense (income)			(29	)			54				25			(34	)			—				(9	)
Income (loss) before income tax expense			(11,033	)			18,318				7,285			50,692				(2,881	)			55,096
Income tax expense (benefit)			6,341				(6,341	)			—			—				—				—
Net income (loss)		$	(17,374	)		$	24,659			$	7,285		$	50,692			$	(2,881	)		$	55,096
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

Three Months Ended March 31, 2010

 

		Partnership Historical				Adjustments for the Offering				Partnership Pro Forma as Adjusted
		(In thousands except per unit data)
Revenues		$	95,386			$	—			$	95,386
Expenses:
Operating expenses			30,693				—				30,693
Depreciation and amortization expense			21,950				—				21,950
General and administrative expense			7,250				500	(g)			7,750
(Gain) loss on sale of assets			(30	)			—				(30	)
Total operating expenses			59,863				500				60,363
Operating income (loss)			35,523				(500	)			35,023
Interest expense			611				(611	)(h)			431
			—				431	(i)			—
Other expense (income)			(2	)			—				(2	)
Income (loss) before income tax expense			34,914				(320	)			34,594
Income tax expense (benefit)			—				—				—
Net income (loss)		$	34,914			$	(320	)		$	34,594
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 consolidated historical financial statements of Chesapeake Midstream Development, L.P. and its subsidiaries (Chesapeake Midstream Development or our Predecessor) and Chesapeake Midstream Partners, L.L.C. and its subsidiaries (Chesapeake Midstream Partners or Successor). In connection with this offering, a portion of the business of Chesapeake Midstream Partners, 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 Chesapeake Midstream Partners. 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 March 31, 2010, in the case of the pro forma balance sheet, and as of January 1, 2009, in the case of the pro forma statements of operations for the year ended December 31, 2009 and for the three months ended March 31, 2010. The pro forma financial data also does not give effect, prior to October 1, 2009, to our 20-year gas gathering agreement with Chesapeake and the other transaction documents that were originally entered into on September 30, 2009, in connection with the formation of Successor.

The pro forma adjustments reflected herein assume no exercise of the underwriters’ option to purchase additional common units. The proceeds from any exercise of the underwriters’ option to purchase additional common units will be distributed to 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 historical results of operations to be retained by our Predecessor were identified based on the actual gathering systems contributed to Successor. The gathering systems retained by our Predecessor comprised those systems which are less mature, and therefore have not achieved their full revenue and cash flow generating capacity, although a significant investment has been made to prepare for expected future growth in the throughput levels going forward. For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Chesapeake Midstream Partners, L.P. and Our Predecessor” and “—Items Impacting the Comparability of our Financial Results”;

 

(b)

the payment of a $150 million cash distribution to members on May 4, 2010 with $15.5 million of cash on hand and the proceeds of $134.5 million of borrowings under our revolving credit facility, which will be repaid at the closing of the offering;

 

(c)

the gross proceeds of $425 million from the issuance and sale of              common units at an assumed initial public offering price of $             per unit;

 

(d)

the payment of estimated underwriting discounts and commissions and structuring fees;

 

(e)

the payment of offering expenses and expenses related to amending and restating our revolving credit facility;

 

(f)

the use of proceeds to pay down outstanding borrowings under the Partnership’s revolving credit facility;

 

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(g)

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 Act 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;

 

(h)

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; and

 

(i)

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.

 

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, 2009. 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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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

 

		Successor
		As of March 31, 2010				As of December 31, 2009
		(In thousands)
Assets
Current assets
Cash and cash equivalents		$	15,507			$	3
Accounts receivable, including $39,764 and $165,065 from related parties at March 31, 2010 and December 31, 2009, respectively			45,436				165,771
Other current assets			1,969				1,743
Total current assets			62,912				167,517
Property, plant and equipment
Gathering systems			2,044,255				2,013,347
Other fixed assets			35,284				34,130
Less: Accumulated depreciation			(291,114	)			(271,062	)
Total property, plant and equipment, net			1,788,425				1,776,415
Long-term assets
Deferred loan costs, net			13,403				14,743
Deferred issuance costs			971				—
Total long-term assets			14,374				14,743
Total assets		$	1,865,711			$	1,958,675
Liabilities and Equity
Current liabilities
Accounts payable		$	27,479			$	22,940
Accrued liabilities, including $20,149 and $84,708 due to related parties at March 31, 2010 and December 31, 2009, respectively			31,810				95,158
Total current liabilities			59,289				118,098
Long-term liabilities
Revolving bank credit facility			—				44,100
Other liabilities			2,903				2,850
Total long-term liabilities			2,903				46,950
Commitments and contingencies (Note 7)
Equity
Members’ equity			1,803,519				1,793,627
Total equity			1,803,519				1,793,627
Total liabilities and equity		$	1,865,711			$	1,958,675

The accompanying notes are an integral part of these financial statements.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

 

		Successor						Predecessor
		Three Months Ended March 31, 2010						Three Months Ended March 31, 2009
		(In thousands)						(In thousands)
Revenues, including revenue from affiliates (Note 5)		$	95,386					$	110,034
Expenses:
Operating expenses, including expenses from affiliates (Note 6)			30,693						48,469
Depreciation and amortization expense			21,950						19,175
General and administrative expense, including expenses from affiliates (Note 6)			7,250						4,487
Gain on sale of assets			(30	)					(778	)
Total operating expenses			59,863						71,353
Operating income			35,523						38,681
Interest expense, net of capitalized interest of $323 and $1,848 for the periods ended March 31, 2010 and March 31, 2009, respectively			611						182
Other income			(2	)					(2	)
Income before income tax expense			34,914						38,501
Income tax expense			—						2,248
Net income		$	34,914					$	36,253

The accompanying notes are an integral part of these financial statements.

 

F-9

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

		Successor						Predecessor
		Three Months Ended March 31, 2010						Three Months Ended March 31, 2009
		(In thousands)						(In thousands)
Cash flows from operating activities
Net income		$	34,914					$	36,253
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			21,950						19,175
Deferred income taxes			—						2,248
Gain on sale of assets			(30	)					(778	)
Other non-cash items			(988	)					(110	)
Changes in assets and liabilities
Decrease in accounts receivable			120,362						11,681
(Increase) decrease in other assets			(226	)					164
Increase (decrease) in accounts payable			3,655						(41,808	)
Increase (decrease) in accrued liabilities			(61,312	)					3,226
Net cash provided by operating activities			118,325						30,051
Cash flows from investing activities
Additions to property, plant and equipment			(39,451	)					(387,444	)
Proceeds from sale of assets			53						1,015
Net cash used in investing activities			(39,398	)					(386,429	)
Cash flows from financing activities
Contributions from Chesapeake			—						570,000
Proceeds from long-term debt borrowings			84,400						377,800
Payments on long-term debt borrowings			(128,500	)					(673,400	)
Distribution to Member			(19,500	)					—
Contribution from Predecessor			177						—
Net cash used in financing activities			(63,423	)					274,400
Net increase (decrease) in cash and cash equivalents			15,504						(81,978	)
Cash and cash equivalents
Beginning of period			3						82,025
End of period		$	15,507					$	47
Supplemental disclosure of non-cash investing activities
Changes in accounts payable related to purchases of property, plant and equipment		$	2,799					$	13,878
Changes in other liabilities related to asset retirement obligations		$	53					$	88
Contributions of property, plant and equipment to (from) Chesapeake		$	9,162					$	(266	)
Supplemental disclosure of cash payments for interest		$	369					$	1,388

The accompanying notes are an integral part of these financial statements.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(UNAUDITED)

 

		Members’ Equity
		(In thousands)
Balance at December 31, 2009		$	1,793,627
Distribution to Predecessor			(5,522	)
Distribution to Member			(19,500	)
Net income			34,914
Balance at March 31, 2010		$	1,803,519

The accompanying notes are an integral part of these financial statements.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

 

1.	Organization and Nature of Business

Organization

Chesapeake Midstream Development, L.P. (“CMD” or “Predecessor”) 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 (“Chesapeake”), were contributed to CMD. CEMI is the sole limited partner of CMD with a 98% ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a 2% ownership interest. CMM is a wholly owned subsidiary of CEMI.

CMD’s operations are conducted through the following wholly owned subsidiaries: Bluestem Gas Services, L.L.C., Texas Midstream Gas Services, L.L.C., Arkansas Midstream Gas Services Corp., AMGS, L.L.C., 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 owned by Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of CMD.

On September 30, 2009, our Predecessor formed a joint venture with Global Infrastructure Partners – A, L.P. and affiliated funds managed by Global Infrastructure Management, LLC, and their respective subsidiaries and affiliates (“GIP”), through which such funds hold their interests in Successor, to own and operate natural gas midstream assets. As part of the transaction, our Predecessor contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. (“CMP” or “Successor”), and GIP purchased a 50% interest in the newly formed joint venture.

Nature of Business

The assets contributed to the joint venture were substantially all of our Predecessor’s midstream assets in the Barnett Shale and certain of its midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. The underlying assets consist of approximately 2,800 miles of gathering pipeline, two CO ₂ /H ₂ S extraction facilities and eight small hydrocarbon dew point control facilities. Subsidiaries of our Predecessor continue to operate midstream assets outside of the Successor joint venture. These include natural gas gathering assets primarily in the Fayetteville Shale, Haynesville Shale, Marcellus Shale and other areas in the Appalachian Basin.

 

2.	Basis of Presentation

The accompanying condensed consolidated financial statements are presented for Predecessor and Successor periods, which relate to the accounting periods preceding and succeeding the September 30, 2009 joint venture transaction described in Note 1. The Predecessor and Successor periods have been separated by a vertical line on the face of the condensed consolidated financial statements to highlight the fact that the financial information for such periods represents different entities. The accompanying financial statements and related notes present the consolidated financial position and changes in members’ equity of the Successor as of March 31, 2010 and December 31, 2009, and the consolidated results of operations and cash flows for the Successor for the three month period ended March 31, 2010, and for the Predecessor for the three month period ended March 31, 2009.

The interim financial data as of March 31, 2010 and for the three months ended March 31, 2010 and March 31, 2009, 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.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

 

3.	Revolving Bank Credit Facilities

Predecessor Credit Facility

On October 16, 2008, our Predecessor closed on a revolving bank credit facility with total commitments of $460 million. All of our Predecessor’s assets are pledged as collateral under this agreement. Until its amendment and restatement effective September 30, 2009, borrowings under the credit facility bore 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 Interbank Offered Rate (LIBOR) plus 1.50%. The unused portion of the credit facility was subject to a commitment fee that varied from 0.30% to 0.45%.

The credit facility agreement contained various covenants and restrictive provisions which, among other things, limited the ability of our Predecessor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. The credit facility agreement required 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. The credit facility agreement also had cross default provisions that applied to other indebtedness our Predecessor and its subsidiaries may have had with an outstanding principal amount in excess of $15 million.

Concurrent with the formation of the Successor, as discussed in Note 1, 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, our Predecessor amended and restated the existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under the credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, our Predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. The Successor capitalized $11.5 million associated with the new $500 million credit facility.

Successor Credit Facility

The Successor revolving bank credit facility matures in September 2012. Borrowings under the Successor credit facility are secured by all of the assets of the Successor, and bear interest at the Successor’s option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, 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 (as defined) 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 Successor credit facility is subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals. At March 31, 2010 and December 31, 2009, there were $0 and $44.1 million, respectively, of outstanding borrowings under the Successor credit facility.

The Successor credit facility agreement requires maintenance of a consolidated leverage ratio of not more than 3.50 to 1, and an interest coverage ratio (as defined) of not less than 3.00 to 1. As defined by the Successor credit facility at March 31, 2010, the consolidated leverage ratio was 0.03 to 1 and the interest coverage ratio was 21.14 to 1.

Additionally, the Successor credit facility contains various covenants and restrictive provisions which, among other things, limit the ability of the Successor and its subsidiaries to incur additional indebtedness, make

 

F-13

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

 

investments or loans, create liens and pay dividends or distributions. If the Successor should fail to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the Successor credit facility could be declared immediately due and payable. The Successor credit facility agreement also has cross default provisions that apply to any other indebtedness the Successor 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 available at March 31, 2010 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

 

4.	Stock-Based Compensation

Chesapeake’s stock-based compensation programs consist of restricted stock issued to employees and non-employee directors. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, the Successor restricted stock expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to the Successor and our Predecessor and are reflected as operating expenses. Included in operating expenses is stock based compensation of $0.6 million and $1.7 million during the periods ended March 31, 2010 and March 31, 2009, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Successor and our Predecessor through an overhead allocation and are reflected as general and administrative expenses.

 

5.	Major Customers and Concentration of Credit Risk

Financial instruments that potentially subject the Successor/our Predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On March 31, 2010 and December 31, 2009, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings, respectively. CEMI accounted for $82.5 million and $108.5 million of revenues for the periods ended March 31, 2010 and March 31, 2009, respectively. Total Gas and Power North America, Inc. accounted for $10.3 million and $0 revenues for the three months ended March 31, 2010 and March 31, 2009, respectively. Management believes that a loss of these customers would have a material impact on operating results as there can be no assurance that a replacement customer would be identified and accessed in a timely fashion or at comparable margins.

 

6.	Transactions with Affiliates

In the normal course of business, natural gas gathering and treating services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells.

Certain gathering assets are held under an agreement with a subsidiary of Chesapeake.

 

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Index to Financial Statements

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

 

In addition, Chesapeake and its affiliates provide certain services including legal, accounting, treasury, human resources, information technology and administration. The employees supporting these operations are employees of CEMI or Chesapeake. The financial statements include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Prior to the completion of the credit facility, allocated costs were based on identification of Chesapeake’s resources which provided a direct benefit and the proportionate share of costs based on estimated usage of shared resources and functions. Costs were allocated based on the proportionate share of Chesapeake’s headcount, compensation expense, or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if our Predecessor had been operated as a stand-alone entity. General and administrative charges allocated by Chesapeake were $3.9 million and $3.7 million for the periods ended March 31, 2010 and March 31, 2009, respectively. Effective October 15, 2008, as part of the terms of the omnibus agreement, the overhead rate charged to our Predecessor became $0.02/Mmbtu. Effective June 1, 2009, the allocated charges from Chesapeake were based on the actual costs for the period as opposed to the $0.02/mmbtu fee. Effective October 1, 2009, the Successor is charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs will be charged to the Successor based on a fee per mcf of natural gas gathered. The mcf fee is calculated as the lesser of $0.03/Mcf gathered or actual corporate overhead costs.

Chesapeake and its affiliates also provide compression services. Monthly compressor rentals are charged to Predecessor under short-term contracts at market rates. Successor is charged for compressor rentals based on a long-term compressor rental agreement with Chesapeake and its subsidiaries. For the periods ended March 31, 2010 and 2009, compressor rental charges from affiliates were $12.4 million and $12.0 million, respectively, and are included in operating expenses in the accompanying consolidated statements of operations.

 

7.	Commitments and Contingencies

Certain real property, equipment and operating facilities are leased under various operating leases. Costs are also incurred 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.

Our Predecessor/Successor is from time to time subject to various legal actions and claims incidental to its business, including those arising out of employment-related matters. Management believes that these routine legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows. Once it is determined that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to the estimate of the likely exposure. There was not an accrual for legal contingencies as of March 31, 2010 and December 31, 2009.

 

8.	Recently Issued Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by our Predecessor and the Successor to determine the potential impact on the financial statements upon adoption.

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

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(UNAUDITED)

 

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 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 holders of IDRs 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 holders of IDRs. 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 holders of IDRs. 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. This guidance will be evaluated if and when the Successor issues securities in the future.

 

9.	Subsequent Events

On May 4, 2010, Succesor paid a distribution of $150 million, which distribution was funded through cash on hand and borrowings under Successor’s revolving credit facility, consisting of $75 million payments to each of its members. Any material subsequent events have been considered for disclosure through the date of issuance, May 21, 2010.

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the members of Chesapeake Midstream Partners, L.L.C:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statement of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Chesapeake Midstream Partners, L.L.C. and its subsidiaries (Successor) (the “Company”) at December 31, 2009, and the results of their operations and their cash flows for the period from October 1, 2009 to December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these 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 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 audit provides a reasonable basis for our opinion.

As discussed in the accompanying consolidated financial statements and footnotes, Chesapeake Midstream Partners, L.L.C. earned substantially all of its revenues from, and has other significant transactions with, affiliated entities.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

April 6, 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 sheet and the related consolidated statements of operations, of changes in equity and of cash flows present fairly, in all material respects, the financial position of Chesapeake Midstream Development, L.P. and its subsidiaries (Predecessor) (the “Partnership”) at December 31, 2008, and the results of their operations and their cash flows for the period from January 1, 2009 to September 30, 2009, and the years ended December 31, 2008 and 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these 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 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, Chesapeake Midstream Development, L.P. earned substantially all of its revenues and has other significant transactions with affiliated entities.

/s/ PricewaterhouseCoopers LLP

Tulsa, Oklahoma

April 6, 2010

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

		Successor						Predecessor
		As of December 31, 2009						As of December 31, 2008
		(In thousands)
Assets
Current assets
Cash and cash equivalents		$	3					$	82,025
Accounts receivable, including $165,065 and $150,616 from related parties at December 31, 2009 and 2008, respectively			165,771						151,909
Other current assets			1,743						377
Total current assets			167,517						234,311
Property, plant and equipment
Gathering systems			2,013,347						2,450,298
Other fixed assets			34,130						15,924
			2,047,477						2,466,222
Less: Accumulated depreciation			(271,062	)					(126,749	)
Total property, plant and equipment, net			1,776,415						2,339,473
Long-term assets
Deferred loan costs, net			14,743						9,981
Total assets		$	1,958,675					$	2,583,765
Liabilities and Equity
Current liabilities
Accounts payable, including $0 and $41,239 due to related parties at December 31, 2009 and 2008, respectively		$	22,940					$	286,400
Accrued liabilities, including $84,708 and $0 due to related parties at December 31, 2009 and 2008, respectively			95,158						8,643
Total current liabilities			118,098						295,043
Long-term liabilities
Deferred income taxes			—						29,806
Revolving bank credit facility			44,100						460,000
Other liabilities			2,850						5,647
Total long-term liabilities			46,950						495,453
Commitments and contingencies (Notes 9 and 10)
Equity
Members’ equity			1,793,627						—
General partner (2.0% interest)			—						35,865
Limited partner (98.0% interest)			—						1,757,404
Total equity			1,793,627						1,793,269
Total liabilities and equity		$	1,958,675					$	2,583,765

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		Successor						Predecessor
		October 1, 2009 through December 31, 2009						January 1, 2009 through September 30, 2009				Year Ended December  31, 2008				Year Ended December  31, 2007
		(In thousands)						(In thousands)
Revenues, including revenue from affiliates (Note 7)		$	107,377					$	358,921			$	332,783			$	191,931
Expenses:
Operating expenses, including expenses from affiliates (Notes 2 and 8)			31,874						146,604				141,803				77,589
Depreciation and amortization expense			20,699						65,477				47,558				24,505
General and administrative expense, including expenses from affiliates (Notes 2 and 8)			3,493						22,782				13,362				6,880
Impairment of property, plant and equipment and other assets			—						90,207				30,000				—
(Gain) loss on sale of assets			34						44,566				(5,541	)			—
Total operating expenses			56,100						369,636				227,182				108,974
Operating income (loss)			51,277						(10,715	)			105,601				82,957
Interest expense, net			619						347				1,871				—
Other expense (income)			(34	)					(29	)			(278	)			—
Income (loss) before income tax expense			50,692						(11,033	)			104,008				82,957
Income tax (benefit) expense			—						6,341				(61,287	)			31,109
Net income (loss)		$	50,692					$	(17,374	)		$	165,295			$	51,848

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

		Division Equity				General Partner Interest				Limited Partner Interest				Non- controlling Interest				Total Equity
		(In thousands)
Predecessor:
Balance at January 1, 2007		$	325,951			$	—			$	—			$	—			$	325,951
Contributions from Chesapeake			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 Chesapeake			—				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
Contributions from Chesapeake			—				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
																		Members’ Equity
Successor:
Members’ equity upon formation																		$	1,741,186
Contributions from Predecessor																			1,749
Net income																			50,692
Balance at December 31, 2009																		$	1,793,627

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		Successor						Predecessor
		October 1, 2009 through December 31, 2009						January 1, 2009 through September 30, 2009				Year Ended December  31, 2008				Year Ended December  31, 2007
		(In thousands)						(In thousands)
Cash flows from operating activities
Net income (loss)		$	50,692					$	(17,374	)		$	165,295			$	51,848
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			20,699						65,477				47,558				24,505
Deferred income taxes			—						6,341				(61,287	)			31,109
Impairment of property, plant and equipment and other assets			—						90,207				30,000				—
(Gain) loss on sale of assets			34						44,566				(5,541	)			—
Other non-cash items			(39	)					(282	)			(537	)			(603	)
Changes in assets and liabilities
(Increase) decrease in accounts receivable			(70,792	)					(29,553	)			(107,863	)			(22,192	)
Decrease in other assets			(136	)					(1,901	)			(138	)			(62	)
Increase (decrease) in accounts payable			(23,630	)					(82,112	)			163,372				7,913
Increase in accrued liabilities			37,902						25,379				5,915				1,430
Net cash provided by operating activities			14,730						100,748				236,774				93,948
Cash flows from investing activities
Additions to property, plant and equipment			(46,377	)					(756,883	)			(1,402,449	)			(563,564	)
Proceeds from sale of assets			25						65,889				17,615				—
Net cash used in investing activities			(46,352	)					(690,994	)			(1,384,834	)			(563,564	)
Cash flows from financing activities
Contributions from Parent			—						567,828				780,553				469,622
Proceeds from long-term debt borrowings			100,744						870,373				508,900				—
Payments on long-term debt borrowings			(68,817	)					(1,318,200	)			(48,900	)			—
Proceeds from sale of noncontrolling interest			—						587,500				—				—
Distributions to joint venture partner			—						(10,153	)			—				—
Joint venture transaction costs			—						(16,130	)			—				—
Offering costs of long-term debt			(337	)					(16,950	)			(10,494	)			—
Net cash provided by financing activities			31,590						664,268				1,230,059				469,622
Net increase (decrease) in cash and cash equivalents			(32	)					74,022				81,999				6
Cash and cash equivalents
Beginning of period			35						82,025				26				20
End of period		$	3					$	156,047			$	82,025			$	26
Supplemental disclosure of non-cash investing
Changes in accounts payable related to purchases of property, plant and equipment		$	(2,812	)				$	(52,521	)		$	58,458			$	40,050
Changes in other liabilities related to asset retirement obligations		$	136					$	(2,893	)		$	1,560			$	4,032
Contributions of property, plant and equipment from Chesapeake		$	1,749					$	91,462			$	—			$	—
Supplemental disclosure of cash payments for interest		$	877					$	7,478			$	1,152			$	—

The accompanying notes are an integral part of these financial statements.

 

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CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND SUBSIDIARIES AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.	Organization and Nature of Business

Organization

Chesapeake Midstream Development, L.P. (“CMD” or “Predecessor”) 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 (“Chesapeake”), were contributed to CMD. CEMI is the sole limited partner of CMD with a 98% ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a 2% ownership interest. CMM is a wholly owned subsidiary of CEMI.

CMD’s operations are conducted through the following wholly owned subsidiaries: Bluestem Gas Services, L.L.C., Texas Midstream Gas Services, L.L.C., Arkansas Midstream Gas Services Corp., AMGS, L.L.C., 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 owned by Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of CMD.

On September 30, 2009, our Predecessor formed a joint venture with 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 Successor (“GIP”), to own and operate natural gas midstream assets. As part of the transaction, our Predecessor contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. (“CMP” or “Successor”), and GIP purchased a 50% interest in the newly formed joint venture for $588 million.

The $870.6 million noncontrolling interest included in our Predecessor’s consolidated equity at September 30, 2009 represents GIP’s 50% interest in the net assets of Successor, which were recorded by Successor at Chesapeake’s historical cost basis of approximately $1.7 billion. This noncontrolling interest includes the $587.5 million GIP contributed in exchange for a 50% ownership interest in Successor, $293.2 million of Chesapeake partners’ capital allocated to GIP in order to properly reflect GIP’s 50% interest in the carrying value of Successor’s net assets and a $10.2 million distribution to GIP for its proportionate share of transaction costs associated with the formation of the joint venture.

Nature of Business

The assets contributed to the joint venture were substantially all of our Predecessor’s midstream assets in the Barnett Shale and certain of its midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. The underlying assets consist of approximately 2,830 miles of gathering pipeline, two CO ₂ /H ₂ S extraction facilities and eight small hydrocarbon dew point control facilities. Subsidiaries of our Predecessor continue to operate midstream assets outside of Successor’s joint venture. These include natural gas gathering assets primarily in the Fayetteville Shale, Haynesville Shale, Marcellus Shale and other areas in the Appalachian Basin.

 

2.	Basis of Presentation

The accompanying consolidated financial statements are presented for Predecessor and Successor periods, which relate to the accounting periods preceding and following the September 30, 2009 joint venture transaction described in Note 1. The Predecessor and Successor periods have been separated by a vertical line on the face of the consolidated financial statements to highlight the fact that the financial information for such periods represents

 

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different entities. The accompanying financial statements and related notes present the consolidated financial position of Successor as of December 31, 2009 and our Predecessor as of December 31, 2008, and the consolidated results of operations, cash flows and changes in partners’ capital/division equity for Successor for the three month period ended December 31, 2009, and for our Predecessor for the nine month period ended September 30, 2009, and the years ended December 31, 2008 and December 31, 2007.

The accompanying consolidated financial statements and related notes include the accounts of our Predecessor and its subsidiaries, all of which were wholly owned, and prior to February 29, 2008, include the assets, liabilities and operations of the midstream business that were contributed to our Predecessor by CEMI upon its formation presented on a carve out basis. As our Predecessor and CEMI had common ownership, the assets and liabilities transferred were carried forward to our Predecessor and are presented for all periods at their historical costs. At the date of the contribution to our Predecessor, the division equity of the midstream business was reclassified as partners’ capital of our Predecessor.

Our Predecessor’s financing requirements have been managed historically with cash generated by operations and equity contributions from Chesapeake. Chesapeake’s corporate level debt issuances and associated interest expense, which generally financed operations outside of our Predecessor’s operations, are not reflected in our Predecessor’s historical financial statements. On October 15, 2008, our Predecessor entered into a revolving credit facility agreement with total commitments of $460 million. See Note 4 for further discussion. Prior to the completion of the credit facility agreement in October 2008, certain subsidiaries of our Predecessor were guarantors for substantially all of Chesapeake’s debt. Payment of the debt of Chesapeake was not dependent upon the operations and cash flows of our Predecessor. Upon the completion of the credit facility agreement mentioned above, our Predecessor and its subsidiaries ceased to be guarantors with respect to the debt of Chesapeake.

Prior to the completion of the credit facility, 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 of our Predecessor is reflected as contributions from Chesapeake in the statements of partners’ capital/division equity.

Transactions between Successor, our Predecessor and Chesapeake or its affiliates have been identified in the financial statements as transactions between affiliates (see Notes 7 and 8). All significant intercompany accounts and transactions have been eliminated in the preparation of the accompanying financial statements.

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 $0.6 million, $4.3 million, $35.4 million and $13.0 million for the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and December 31, 2007, respectively. For the period ended December 31, 2009, our Predecessor allocated $7.6 million in operating expenses to Successor for payroll and benefits for employees directly involved in Successor’s gathering and treating operations.

The accompanying financial statements include allocated charges from Chesapeake 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 Chesapeake were $2.2 million, $14.6 million, $11.3 million and $6.9 million for the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and 2007, respectively. Management believes that the allocated general and administrative expense is representative of the costs and expenses incurred by Chesapeake for Successor and our Predecessor. Effective October 15, 2008, as part of the terms of an omnibus agreement, the overhead rate charged to our Predecessor became $0.02/mmbtu. Effective June 1, 2009, the allocated charges from Chesapeake were

 

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based on the actual costs for the period as opposed to the $0.02/mmbtu fee. Effective October 1, 2009, Successor was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs will be charged to Successor based on a fee per mcf of natural gas gathered. The fee is calculated as the lesser of $0.03/mcf gathered or actual corporate overhead costs. See Note 8 for further discussion.

 

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. Significant estimates include: (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 management believes these estimates are reasonable, actual results could differ from its estimates.

Cash and Cash Equivalents

For purposes of the consolidated financial statements, investments in all highly liquid instruments with original maturities of three months or less at date of purchase are considered 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, 2009 and 2008, book overdrafts of $4.0 million and $42.0 million were included in accounts payable.

Accounts Receivable

The majority of accounts receivable relate to 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, 2009 and 2008, 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 operating expenses in the statements of operations. Our Predecessor recorded a $44.6 million loss on the sale of certain non-core, non-strategic gathering systems during the period ended September 30, 2009 as well as a $5.5 million gain on the sale of certain gathering systems sold in conjunction with an upstream transaction effected by Chesapeake during the year ended December 31, 2008.

Certain of the gathering systems of Successor are subject to an agreement with a subsidiary of Chesapeake, which agreement provides Successor rights and obligations equivalent to a capital lease. Under the terms of the agreement, Successor has rights to the associated capital assets for as long as the assets are in operation. Specifically, Successor 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, Successor receives revenues derived from operation of the gathering systems. At December 31, 2009, approximately $120.9 million ($113.7 million net of accumulated depreciation)

 

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of Successor’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, Successor has no capital lease obligation liability associated with the assets held under this agreement as of December 31, 2009.

Property, plant and equipment consisted of the following at December 31:

 

				Successor						Predecessor
		Estimated Useful Lives (Years)		December 31, 2009						December 31, 2008
				(In thousands)						(In thousands)
Gathering systems		20		$	2,013,347					$	2,450,298
Other fixed assets		2 through 39			34,130						15,924
Property, plant and equipment, gross					2,047,477						2,466,222
Less: Accumulated depreciation					(271,062	)					(126,749	)
Property, plant and equipment, net				$	1,776,415					$	2,339,473

Depreciation expense for the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and December 31, 2007 was $19.2 million, $64.4 million, $46.5 million, $24.5 million, respectively. Included in gathering systems is $383.8 million and $679.1 million at December 31, 2009 and 2008, respectively, that is not subject to depreciation as the systems were under construction and have not been put into service.

Depreciation is calculated using the straight-line method, based on the assets estimated useful lives. 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.

Interest is capitalized on gathering systems using an interest rate based on outstanding borrowings. Interest capitalized was $0.3 million and $6.5 million in the period ended December 31, 2009 and September 30, 2009. There was no interest capitalized for the years ended December 31, 2008 and 2007.

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 the 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 that the carrying value exceeds the fair value of the asset is recognized. Fair value is determined using an income approach whereby the expected future cash flows are discounted using a rate management believes a market participant would assume is reflective of the risks associated with achieving the underlying cash flows.

During 2009, our Predecessor recognized an impairment charge of $86.2 million associated with certain mid-continent gathering systems. The impairment was the result of a reduction in the future expected throughput volumes on these systems by Chesapeake based on its revised future development plans of the underlying oil and gas properties, as well as the impact of the terms of the new gas gathering agreements entered into with Chesapeake in conjunction with the formation of Successor’s joint venture on September 30, 2009. These systems were subsequently contributed to Successor upon its formation. Additionally, our Predecessor also expensed $4 million of debt issuance costs as a result of the amendment of the credit facility (See Note 4) resulting in total impairments of $90.2 million in 2009.

During 2008, CMD recognized a charge of $30 million associated with the impairment of a treating facility. The impairment was the result of the facility’s location in an area of declining production and a reduction in the

 

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future expected throughput volumes by Chesapeake, based on their revised future development plans on the associated oil and gas properties that serve as the primary source of throughput volume for the facility. The treating facility was subsequently contributed to Successor upon its formation.

Deferred Loan Costs

External costs incurred in connection with closing the revolving bank credit facilities are capitalized as deferred loan costs and amortized over the life of the related agreement. Amortization is included in depreciation and amortization expense in the statement of operations.

Asset Retirement Obligations

Obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets are recognized at fair value in the period in which the liability is incurred.

Certain lease agreements for central compressor stations require properties to be restored to their original condition at the expiration of the lease agreement. In these cases, the estimated cost to remove the facilities and otherwise restore the property to its original condition has been recorded as a liability which is included in other long-term liabilities. The asset retirement cost is capitalized as part of the carrying amount of gathering systems. 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 asset retirement obligations are shown below:

 

		Successor					Predecessor
		December 31, 2009					December 31, 2008
		(In thousands)					(In thousands)
Asset retirement obligations, beginning of period		$	2,714				$	4,032
Additions			—					1,259
Accretion expense			136					301
Asset retirement obligations, end of period		$	2,850				$	5,592

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. There are no liabilities reflected in the accompanying financial statements at December 31, 2009 and 2008.

Revenue Recognition

Our Predecessor’s revenues are derived almost exclusively from related parties and are charged under short-term contracts at market sensitive rates. Successor currently derives substantially all of its revenues through gas gathering agreements with Chesapeake. Pursuant to the gas gathering agreements, Chesapeake has agreed to minimum volume commitments covering production in the Barnett Shale region for each year through December 31, 2018 and for the six month period ending June 30, 2019. In the event Chesapeake does not meet its minimum volume commitment 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, as applicable, will be obligated to pay 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

 

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gathered 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 compression of natural gas to major interstate and intrastate pipelines. Revenues are recognized when the service is performed and is based upon non-regulated rates and the related gathering, treating and compression volumes.

Income Taxes

Chesapeake and its subsidiaries historically have filed a consolidated federal income tax return and other state returns as required. Our Predecessor and certain of its subsidiaries, as a partnership or limited liability companies, were not subject to federal income taxes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to the partners of our Predecessor and, accordingly, do not result in a provision for income taxes in the accompanying financial statements. As a limited liability company, Successor is classified as a partnership for income tax purposes and is also not subject to federal income taxes and most state income taxes with the exception of Texas franchise tax. For federal and state income tax purposes other than Texas, all income, expenses, gains, losses and tax credits generated flow through to the partners of Successor, and accordingly, do not result in a provision for income taxes.

Income taxes have been provided by our Predecessor 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 our Predecessor 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 of our Predecessor. These differences create taxable or tax deductible amounts for future periods. Current taxes payable of Successor related to Texas franchise tax will be paid by Successor. Current taxes payable of our Predecessor were paid by Chesapeake and have been reflected as contributions from Chesapeake in the accompanying statements of partners’ capital/division equity. Chesapeake reimbursed our Predecessor for its net operating losses utilized in the completion of Chesapeake’s consolidated federal tax returns.

There were no uncertain tax positions at December 31, 2009 and 2008.

 

4.	Revolving Bank Credit Facilities

Predecessor Credit Facility

On October 16, 2008, our Predecessor closed on a revolving bank credit facility with total commitments of $460 million. As of December 31, 2008, our Predecessor had $460 million in outstanding borrowings under the credit facility. All of our Predecessor’s assets are pledged as collateral under this agreement. Until its amendment and restatement effective September 30, 2009, borrowings under the credit facility bore 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 Interbank Offered Rate (LIBOR) plus 1.50%. The unused portion of the credit facility was subject to a commitment fee that varied from 0.30% to 0.45%.

The credit facility agreement contained various covenants and restrictive provisions which, among other things, limited the ability of our Predecessor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. The credit facility agreement required 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, our Predecessor’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. The credit facility agreement also had cross default provisions that applied to other indebtedness our Predecessor and its subsidiaries may have had with an outstanding principal amount in excess of $15 million.

 

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Concurrent with the formation of Successor, as discussed in Note 1, 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, our Predecessor amended and restated the existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under the credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, our Predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. Successor capitalized $11.5 million associated with the new $500 million credit facility.

Successor Credit Facility

Successor’s revolving bank credit facility matures in September 2012. Borrowings under Successor’s credit facility are secured by all of the assets of Successor, and bear interest at Successor’s option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, 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 (as defined) 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 Successor’s credit facility is subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest is payable quarterly or, if LIBOR applies, it may be paid at more frequent intervals. At December 31, 2009, there were $44.1 million of outstanding borrowings under Successor’s credit facility.

Successor’s credit facility agreement requires maintenance of a consolidated leverage ratio of not more than 3.50 to 1, and an interest coverage ratio (as defined) of not less than 3.00 to 1. As defined by Successor’s credit facility at December 31, 2009, the consolidated leverage ratio was 0.19 to 1 and the interest coverage ratio was 21.75 to 1.

Additionally, Successor’s credit facility contains various covenants and restrictive provisions which, among other things, limit the ability of Successor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. If Successor should fail to perform its obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under Successor’s credit facility could be declared immediately due and payable. Successor’s credit facility agreement also has cross default provisions that apply to any other indebtedness Successor 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 available at December 31, 2009 and 2008 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

 

5.	Stock-Based Compensation

Chesapeake’s stock-based compensation programs consist of restricted stock issued to employees and non-employee directors. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, Successor restricted stock expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to Successor and our Predecessor and are reflected as operating expenses. Included in operating expenses is stock based compensation of $0.6 million, $5.3 million,

 

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$3.6 million and $2.7 million during the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and 2007, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to Successor and our Predecessor through an overhead allocation and are reflected as general and administrative expenses.

 

6.	Income Taxes

As discussed in Note 3, Successor is a limited liability company and is classified as a partnership for income tax purposes and is also not subject to federal income taxes and most state income taxes. Income tax (benefit) expense for the periods ended September 30, 2009, December 31, 2008 and December 31, 2007 is as follows:

 

		Predecessor
		January 1, 2009 through September 30, 2009			Year Ended December 31, 2008				Year Ended December 31, 2007
		(In thousands)
Current		$	—		$	—			$	—
Deferred			6,341			(61,287	)			31,109
Total income tax (benefit) expense presented in the Statements of Operations		$	6,341		$	(61,287	)		$	31,109

Reconciliation of income tax expense at the U.S. Federal Statutory Income Tax Rate to actual tax expense (Statutory Rate Reconciliation) for the periods ended September 30, 2009, December 31, 2008 and December 31, 2007 is as follows:

 

		Predecessor
		January 1, 2009 through September 30, 2009				Year Ended December 31, 2008				Year Ended December 31, 2007
		(In thousands)
Income tax expense, computed at the statutory rate of 35%		$	(3,862	)		$	36,403			$	29,035
Effect of state income tax, net of federal income tax effect			423				1,022				2,074
Effect of non-taxable entities			9,780				(12,555	)			—
Effect of change in tax status(1)			—				(86,157	)			—
Total income tax (benefit) expense		$	6,341			$	(61,287	)		$	31,109
Effective tax rate			(57.47	)%			(58.93	)%			37.50	%

 

(1)	Certain deferred tax liabilities were eliminated and recognized in earnings in 2008 as a result of the change in tax status of our Predecessor and its subsidiaries.

Net deferred income tax liability components for the year ended December 31, 2008 is as follows:

 

		Predecessor
		2008
		(In thousands)
Net operating losses		$	—
Accelerated depreciation rates			(29,806	)
Total net deferred income tax liabilities		$	(29,806	)

 

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7.	Major Customers and Concentration of Credit Risk

Financial instruments that potentially subject Successor/our Predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On December 31, 2009 and 2008, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings, respectively. CEMI accounted for $106.5 million, $350.5 million, $329.5 million and $187.9 million of revenues for the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and December 31, 2007, respectively, and, as such almost all accounts receivable are due from CEMI. Management believes that a loss of this customer would have a material impact on operating results as there can be no assurance that a replacement customer would be identified and accessed in a timely fashion or at comparable margins.

 

8.	Transactions with Affiliates

In the normal course of business, natural gas gathering and treating services are provided to Chesapeake and its affiliates. Revenues are derived almost exclusively from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells. See Note 3 —“Property, Plant and Equipment” for further discussion of revenue recognition.

Certain gathering assets are held under an agreement with a subsidiary of Chesapeake. See Note 3 for discussion of the agreement.

In addition, Chesapeake and its affiliates provide certain services including legal, accounting, treasury, information technology and administration. The employees supporting these operations are employees of CEMI or Chesapeake. The financial statements include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Prior to the completion of the credit facility, allocated costs were based on identification of Chesapeake’s resources which provided a direct benefit and the proportionate share of costs based on estimated usage of shared resources and functions. Costs were allocated based on the proportionate share of Chesapeake’s headcount, compensation expense, or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if our Predecessor had been operated as a stand-alone entity. Effective October 15, 2008, as part of the terms of the omnibus agreement, the overhead rate charged to our Predecessor became $0.02/mmbtu. Effective June 1, 2009, the allocated charges from Chesapeake were based on the actual costs for the period as opposed to the $0.02/mmbtu fee. Effective October 1, 2009, Successor is charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs will be charged to Successor based on a fee per mcf of natural gas gathered. The mcf fee is calculated as the lesser of $0.03/mcf gathered or actual corporate overhead costs.

Chesapeake and its affiliates also provide compression services. Monthly compressor rentals are charged to our Predecessor under short-term contracts at market rates. Successor is charged for compressor rentals based on a long-term compressor rental agreement with Chesapeake and its subsidiaries. For the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and December 31, 2007, compressor rental charges from affiliates were $11.7 million, $47.3 million, $47.0 million and $20.6 million, respectively, and are included in operating expenses in the accompanying consolidated statements of operations.

 

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9.	Commitments and Contingencies

Certain real property, equipment and operating facilities are leased under various operating leases. Costs are also incurred 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, 2009, are summarized below:

 

		Operating Leases
		(In thousands)
Year Ending December 31
2010		$	45,541
2011			45,269
2012			34,242
2013			1,085
2014			1,120
Thereafter			1,120
Future minimum lease payments		$	128,377

Rental expense related to leases was $11.7 million, $48.2 million, $49.9 million and $26.3 million for the periods ended December 31, 2009, September 30, 2009, December 31, 2008 and December 31, 2007, respectively.

Our Predecessor/Successor is from time to time subject to various legal actions and claims incidental to its business, including those arising out of employment-related matters. Management believes that these routine legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows. Once it is determined that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to the estimate of the likely exposure. There was not an accrual for legal contingencies as of December 31, 2009, 2008 and 2007.

 

10.	Environmental Remediation

Chesapeake 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 management considers reasonable. Consistent with insurance coverage generally available in the industry, in certain circumstances the insurance policies provide limited coverage for losses or liabilities relating to gradual pollution, with broader coverage for sudden and accidental occurrences. Although a program is designed to prevent, as applicable, to detect and address such releases promptly, damages, and liabilities incurred due to environmental releases from assets may substantially affect the business.

At December 31, 2009 and 2008, management of Successor and our Predecessor were not aware of any existing conditions that may cause significant expenditures in the future for the remediation of existing contamination. As such, there are no liabilities reflected in the accompanying financial statements for environmental obligations to be incurred in the future based on existing contamination. Changes in estimates and assumptions may occur as a result of the passage of time and the occurrence of future events.

 

11.	Recently Issued Accounting Standards

The FASB recently issued the following standards which were reviewed by our Predecessor and Successor to determine the potential impact on the financial statements upon adoption.

 

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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, this guidance was adopted as of July 1, 2009. Adoption did not have any material impact on the 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. Adoption did not have any material impact on the 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. This guidance was adopted as of April 1, 2009. Adoption did not have any material impact on the 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 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. This guidance will be evaluated if and when Successor issues securities in the future.

 

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Upon the adoption of the amended accounting standards for variable interest entities on January 1, 2010, our Predecessor 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 our Predecessor’s equity in the joint venture at January 1, 2010, which was originally recorded at carry over basis, and what the fair value of our Predecessor’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 our Predecessor’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 our Predecessor.

 

12.	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 as 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 the date of issuance, April 6, 2010.

 

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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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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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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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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

 

FIRST AMENDED AND RESTATED

AGREEMENT OF LIMITED PARTNERSHIP

OF

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

 

 

 

 

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TABLE OF CONTENTS

 

ARTICLE I
DEFINITIONS
Section 1.1		Definitions		A-1
Section 1.2		Construction		A-21
ARTICLE II
ORGANIZATION
Section 2.1		Formation		A-22
Section 2.2		Name		A-22
Section 2.3		Registered Office; Registered Agent; Principal Office; Other Offices		A-22
Section 2.4		Purpose and Business		A-22
Section 2.5		Powers		A-23
Section 2.6		Term		A-23
Section 2.7		Title to Partnership Assets		A-23
ARTICLE III
RIGHTS OF LIMITED PARTNERS
Section 3.1		Limitation of Liability		A-23
Section 3.2		Management of Business		A-23
Section 3.3		Outside Activities of the Limited Partners		A-24
Section 3.4		Rights of Limited Partners		A-24
ARTICLE IV
CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS
Section 4.1		Certificates		A-25
Section 4.2		Mutilated, Destroyed, Lost or Stolen Certificates		A-25
Section 4.3		Record Holders		A-26
Section 4.4		Transfer Generally		A-26
Section 4.5		Registration and Transfer of Limited Partner Interests		A-26
Section 4.6		Transfer of the General Partner’s General Partner Interest		A-27
Section 4.7		Transfer of Incentive Distribution Rights		A-28
Section 4.8		Restrictions on Transfers		A-38
Section 4.9		Eligibility Certificates; Ineligible Holders		A-29
Section 4.10		Redemption of Partnership Interests of Ineligible Holders		A-30
ARTICLE V
CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS
Section 5.1		Organizational Contributions		A-31
Section 5.2		Contributions by the General Partner and its Affiliates		A-32
Section 5.3		Contributions by Initial Limited Partners		A-32
Section 5.4		Interest and Withdrawal		A-32
Section 5.5		Capital Accounts		A-33
Section 5.6		Issuances of Additional Partnership Securities		A-35
Section 5.7		Conversion of Subordinated Units		A-35
Section 5.8		Limited Preemptive Right		A-36
Section 5.9		Splits and Combinations		A-36
Section 5.10		Fully Paid and Non-Assessable Nature of Limited Partner Interests		A-37

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Section 5.11		Issuance of Common Units in Connection with Reset of Incentive Distribution Rights		A-37
ARTICLE VI
ALLOCATIONS AND DISTRIBUTIONS
Section 6.1		Allocations for Capital Account Purposes		A-38
Section 6.2		Allocations for Tax Purposes		A-45
Section 6.3		Requirement and Characterization of Distributions; Distributions to Record Holders		A-47
Section 6.4		Distributions of Available Cash from Operating Surplus		A-47
Section 6.5		Distributions of Available Cash from Capital Surplus		A-49
Section 6.6		Adjustment of Minimum Quarterly Distribution and Target Distribution Levels		A-49
Section 6.7		Special Provisions Relating to the Holders of Subordinated Units		A-49
Section 6.8		Special Provisions Relating to the Holders of Incentive Distribution Rights		A-50
Section 6.9		Entity-Level Taxation		A-50
ARTICLE VII
MANAGEMENT AND OPERATION OF BUSINESS
Section 7.1		Management		A-51
Section 7.2		Certificate of Limited Partnership		A-52
Section 7.3		Restrictions on the General Partner’s Authority		A-53
Section 7.4		Reimbursement of the General Partner		A-53
Section 7.5		Outside Activities		A-54
Section 7.6		Loans from the General Partner; Loans or Contributions from the Partnership or Group Members		A-55
Section 7.7		Indemnification		A-55
Section 7.8		Liability of Indemnitees		A-57
Section 7.9		Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties		A-57
Section 7.10		Other Matters Concerning the General Partner		A-59
Section 7.11		Purchase or Sale of Partnership Securities		A-59
Section 7.12		Registration Rights of the General Partner and its Affiliates		A-59
Section 7.13		Reliance by Third Parties		A-61
ARTICLE VIII
BOOKS, RECORDS, ACCOUNTING AND REPORTS
Section 8.1		Records and Accounting		A-62
Section 8.2		Fiscal Year		A-62
Section 8.3		Reports		A-62
ARTICLE IX
TAX MATTERS
Section 9.1		Tax Returns and Information		A-63
Section 9.2		Tax Elections		A-63
Section 9.3		Tax Controversies		A-63
Section 9.4		Withholding		A-63
ARTICLE X
ADMISSION OF PARTNERS
Section 10.1		Admission of Limited Partners		A-64
Section 10.2		Admission of Successor General Partner		A-64
Section 10.3		Amendment of Agreement and Certificate of Limited Partnership		A-65

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ARTICLE XI
WITHDRAWAL OR REMOVAL OF PARTNERS
Section 11.1		Withdrawal of the General Partner		A-65
Section 11.2		Removal of the General Partner		A-66
Section 11.3		Interest of Departing General Partner and Successor General Partner		A-66
Section 11.4		Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages		A-68
Section 11.5		Withdrawal of Limited Partners		A-68
ARTICLE XII
DISSOLUTION AND LIQUIDATION
Section 12.1		Dissolution		A-68
Section 12.2		Continuation of the Business of the Partnership After Dissolution		A-69
Section 12.3		Liquidator		A-69
Section 12.4		Liquidation		A-70
Section 12.5		Cancellation of Certificate of Limited Partnership		A-70
Section 12.6		Return of Contributions		A-70
Section 12.7		Waiver of Partition		A-71
Section 12.8		Capital Account Restoration		A-71
ARTICLE XIII
AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE
Section 13.1		Amendments to be Adopted Solely by the General Partner		A-71
Section 13.2		Amendment Procedures		A-72
Section 13.3		Amendment Requirements		A-72
Section 13.4		Special Meetings		A-73
Section 13.5		Notice of a Meeting		A-73
Section 13.6		Record Date		A-74
Section 13.7		Adjournment		A-74
Section 13.8		Waiver of Notice; Approval of Meeting; Approval of Minutes		A-74
Section 13.9		Quorum and Voting		A-74
Section 1310		Conduct of a Meeting		A-75
Section 13.11		Action Without a Meeting		A-75
Section 13.12		Right to Vote and Related Matters		A-75
ARTICLE XIV
MERGER, CONSOLIDATION OR CONVERSION
Section 14.1		Authority		A-76
Section 14.2		Procedure for Merger, Consolidation or Conversion		A-76
Section 14.3		Approval by Limited Partners		A-77
Section 14.4		Certificate of Merger		A-79
Section 14.5		Effect of Merger, Consolidation or Conversion		A-79
ARTICLE XV
RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS
Section 15.1		Right to Acquire Limited Partner Interests		A-80
ARTICLE XVI
GENERAL PROVISIONS
Section 16.1		Addresses and Notices; Written Communications		A-81

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Section 16.2		Further Action		A-81
Section 16.3		Binding Effect		A-81
Section 16.4		Integration		A-82
Section 16.5		Creditors		A-82
Section 16.6		Waiver		A-82
Section 16.7		Third-Party Beneficiaries		A-82
Section 16.8		Counterparts		A-82
Section 16.9		Applicable Law; Forum, Venue and Jurisdiction		A-82
Section 16.10		Invalidity of Provisions		A-83
Section 16.11		Consent of Partners		A-83
Section 16.12		Facsimile Signatures		A-83

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FIRST AMENDED AND RESTATED AGREEMENT

OF LIMITED PARTNERSHIP OF CHESAPEAKE MIDSTREAM PARTNERS, L.P.

THIS FIRST AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. dated as of [                    ], 2010, is entered into by and between Chesapeake Midstream GP, L.L.C., a Delaware limited liability company, as the General Partner, and Chesapeake Midstream Ventures, L.L.C., a Delaware limited liability company, as the Organizational Limited Partner, together with any other Persons who become Partners in the Partnership or parties hereto as provided herein. In consideration of the covenants, conditions and agreements contained herein, the parties hereto hereby agree as follows:

ARTICLE I

DEFINITIONS

Section 1.1 Definitions.

The following definitions shall be for all purposes, unless otherwise clearly indicated to the contrary, applied to the terms used in this Agreement.

“Acquisition” means any transaction in which any Group Member acquires (through an asset acquisition, merger, stock acquisition or other form of investment) control over all or a portion of the assets, properties or business of another Person for the purpose of increasing or expanding, for a period exceeding the short-term, the operating capacity or operating income of the Partnership Group from the operating capacity or operating income of the Partnership Group existing immediately prior to such transaction. For purposes of this definition, the short-term generally refers to a period not exceeding 12 months.

“Additional Book Basis” means the portion of any remaining Carrying Value of an Adjusted Property that is attributable to positive adjustments made to such Carrying Value as a result of Book-Up Events. For purposes of determining the extent that Carrying Value constitutes Additional Book Basis:

(a) Any negative adjustment made to the Carrying Value of an Adjusted Property as a result of either a Book-Down Event or a Book-Up Event shall first be deemed to offset or decrease that portion of the Carrying Value of such Adjusted Property that is attributable to any prior positive adjustments made thereto pursuant to a Book-Up Event or Book-Down Event.

(b) If Carrying Value that constitutes Additional Book Basis is reduced as a result of a Book-Down Event and the Carrying Value of other property is increased as a result of such Book-Down Event, an allocable portion of any such increase in Carrying Value shall be treated as Additional Book Basis; provided, that the amount treated as Additional Book Basis pursuant hereto as a result of such Book-Down Event shall not exceed the amount by which the Aggregate Remaining Net Positive Adjustments after such Book-Down Event exceeds the remaining Additional Book Basis attributable to all of the Partnership’s Adjusted Property after such Book-Down Event (determined without regard to the application of this clause (b) to such Book-Down Event).

“Additional Book Basis Derivative Items” means any Book Basis Derivative Items that are computed with reference to Additional Book Basis. To the extent that the Additional Book Basis attributable to all of the Partnership’s Adjusted Property as of the beginning of any taxable period exceeds the Aggregate Remaining Net Positive Adjustments as of the beginning of such period (the “Excess Additional Book Basis”), the Additional Book Basis Derivative Items for such period shall be reduced by the amount that bears the same ratio to the amount of Additional Book Basis Derivative Items determined without regard to this sentence as the Excess

 

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Additional Book Basis bears to the Additional Book Basis as of the beginning of such period. With respect to a Disposed of Adjusted Property, the Additional Book Basis Derivative items shall be the amount of Additional Book Basis taken into account in computing gain or loss from the disposition of such Disposed of Adjusted Property.

“Adjusted Capital Account” means the Capital Account maintained for each Partner as of the end of each fiscal year of the Partnership, (a) increased by any amounts that such Partner is obligated to restore under the standards set by Treasury Regulation Section 1.704-1(b)(2)(ii)(c) (or is deemed obligated to restore under Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5)) and (b) decreased by (i) the amount of all losses and deductions that, as of the end of such fiscal year, are reasonably expected to be allocated to such Partner in subsequent years under Sections 704(e)(2) and 706(d) of the Code and Treasury Regulation Section 1.751-1(b)(2)(ii), and (ii) the amount of all distributions that, as of the end of such fiscal year, are reasonably expected to be made to such Partner in subsequent years in accordance with the terms of this Agreement or otherwise to the extent they exceed offsetting increases to such Partner’s Capital Account that are reasonably expected to occur during (or prior to) the year in which such distributions are reasonably expected to be made (other than increases as a result of a minimum gain chargeback pursuant to Section 6.1(d)(i) or 6.1(d)(ii)). The foregoing definition of Adjusted Capital Account is intended to comply with the provisions of Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith. The “Adjusted Capital Account” of a Partner in respect of a Partnership Interest shall be the amount that such Adjusted Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Adjusted Operating Surplus” means, with respect to any period, (a) Operating Surplus generated with respect to such period; (b) less (i) the amount of any net increase in Working Capital Borrowings (or the Partnership’s proportionate share of any net increase in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; and (ii) the amount of any net decrease in cash reserves (or the Partnership’s proportionate share of any net decrease in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period not relating to an Operating Expenditure made with respect to such period; and (c) plus (i) the amount of any net decrease in Working Capital Borrowings (or the Partnership’s proportionate share of any net decrease in Working Capital Borrowings in the case of Subsidiaries that are not wholly owned) with respect to that period; (ii) the amount of any net increase in cash reserves (or the Partnership’s proportionate share of any net increase in cash reserves in the case of Subsidiaries that are not wholly owned) for Operating Expenditures with respect to such period required by any debt instrument for the repayment of principal, interest or premium; and (iii) any net decrease made in subsequent periods in cash reserves for Operating Expenditures initially established with respect to such period to the extent such decrease results in a reduction in Adjusted Operating Surplus in subsequent periods pursuant to clause (b)(ii) above. Adjusted Operating Surplus does not include that portion of Operating Surplus included in clause (a)(i) of the definition of Operating Surplus;

provided, that to the extent that actual volumes of natural gas delivered to the gathering systems of the Partnership (associated with a Minimum Volume Commitment) in a particular Quarter or Quarters are less than the prorated (in Quarterly amounts) Minimum Volume Commitment amount for such period, the General Partner may add to Adjusted Operating Surplus for such period an amount equal to such shortfall in actual volumes delivered multiplied by the applicable gathering rate as set forth in the gas gathering or similar agreement (the “Quarterly Estimated Shortfall Payment”). The Quarterly Estimated Shortfall Payment shall be adjusted each subsequent Quarter based on the level of actual volumes delivered for such subsequent Quarter and the preceding Quarters of the period that remain subject to a Minimum Volume Commitment (as compared to the prorated Minimum Volume Commitment for such period). If the sum of Quarterly Estimated Shortfall Payments in

 

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respect of a Minimum Volume Commitment Period is greater than the aggregate shortfall amount actually paid with respect to 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 shortfall amount actually paid as if it had been paid in such Quarter to cover the shortfall in such Quarter. With respect to a Quarter in which a shortfall amount under a Minimum Volume Commitment is actually paid, Adjusted Operating Surplus shall be reduced by an amount equal to the amount of Adjusted Operating Surplus previously added by the General Partner with respect to such Minimum Volume Commitment Period pursuant to this proviso.

“Adjusted Property” means any property the Carrying Value of which has been adjusted pursuant to Section 5.5(d)(i) or 5.5(d)(ii).

“Affiliate” means, with respect to any Person, any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question. As used herein, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise Without limiting the foregoing, for purposes of this Agreement, any Person that, individually or together with its Affiliates, has the direct or indirect right to designate or cause the designation of at least one member to the Board of Directors of the General Partner, and any such Person’s Affiliates, shall be deemed to be Affiliates of the General Partner. Notwithstanding anything in the foregoing to the contrary, the GIP Entities and their respective Affiliates (other than the General Partner or any Group Member), on the one hand, and CHK and its Affiliates (other than the General Partner or any Group Member), on the other hand, will not be deemed to be Affiliates of one another hereunder unless there is a basis for such Affiliation independent of their respective Affiliation with any Group Member, the General Partner or any Affiliate (disregarding the immediately preceding sentence) of any Group Member or the General Partner.

“Aggregate Quantity of IDR Reset Common Units” is defined in Section 5.11(a).

“Aggregate Remaining Net Positive Adjustments” means, as of the end of any taxable period, the sum of the Remaining Net Positive Adjustments of all the Partners.

“Agreed Allocation” means any allocation, other than a Required Allocation, of an item of income, gain, loss or deduction pursuant to the provisions of Section 6.1, including a Curative Allocation (if appropriate to the context in which the term “Agreed Allocation” is used).

“Agreed Value” of any Contributed Property means the fair market value of such property or other consideration at the time of contribution and in the case of an Adjusted Property, the fair market value of such Adjusted Property on the date of the revaluation event as described in Section 5.5(d)(i) or Section 5.5(d)(ii), in both cases as determined by the General Partner. In making such determination, the General Partner shall use such method as it determines to be appropriate to allocate the aggregate Agreed Value of Adjusted Properties or Contributed Properties contributed to the Partnership in a single or integrated transaction among each separate property on a basis proportional to the fair market value of each such property.

“Agreement” means this First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., as it may be amended, supplemented or restated from time to time.

“Associate” means, when used to indicate a relationship with any Person, (a) any corporation or organization of which such Person is a director, officer, manager, general partner or managing member or is, directly or indirectly, the owner of 20% or more of any class of voting stock or other voting interest; (b) any trust or other estate in which such Person has at least a 20% beneficial interest or as to which such Person serves as trustee or in a similar fiduciary capacity; and (c) any relative or spouse of such Person, or any relative of such spouse, who has the same principal residence as such Person.

 

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“Available Cash” means, with respect to any Quarter ending prior to the Liquidation Date:

(a) the sum of (i) all cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand at the end of such Quarter, and (ii) if the General Partner so determines, all or any portion of any additional cash and cash equivalents of the Partnership Group (or the Partnership’s proportionate share of cash and cash equivalents in the case of Subsidiaries that are not wholly owned) on hand on the date of determination of Available Cash with respect to such Quarter resulting from Working Capital Borrowings made subsequent to the end of such Quarter, less

(b) the amount of any cash reserves established by the General Partner (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to (i) provide for the proper conduct of the business of the Partnership Group (including reserves for future capital expenditures and for anticipated future credit needs of the Partnership Group) subsequent to such Quarter, (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which any Group Member is a party or by which it is bound or its assets are subject or (iii) provide funds for distributions under Section 6.4 or 6.5 in respect of any one or more of the next four Quarters;

provided, however, that the General Partner may not establish cash reserves pursuant to clause (iii) above if the effect of such reserves would be that the Partnership is unable to distribute the Minimum Quarterly Distribution on all Common Units, plus any Cumulative Common Unit Arrearage on all Common Units, with respect to such Quarter; and, provided further, that disbursements made by a Group Member or cash reserves established, increased or reduced after the end of such Quarter but on or before the date of determination of Available Cash with respect to such Quarter shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Quarter if the General Partner so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero.

“Board of Directors” means, with respect to the Board of Directors of the General Partner, its board of directors or board of managers, as applicable, if a corporation or limited liability company, or if a limited partnership, the board of directors or board of managers of the general partner of the General Partner.

“Book Basis Derivative Items” means any item of income, deduction, gain or loss that is computed with reference to the Carrying Value of an Adjusted Property (e.g., depreciation, depletion, or gain or loss with respect to an Adjusted Property).

“Book-Down Event” means an event that triggers a negative adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

“Book-Tax Disparity” means with respect to any item of Contributed Property or Adjusted Property, as of the date of any determination, the difference between the Carrying Value of such Contributed Property or Adjusted Property and the adjusted basis thereof for federal income tax purposes as of such date. A Partner’s share of the Partnership’s Book-Tax Disparities in all of its Contributed Property and Adjusted Property will be reflected by the difference between such Partner’s Capital Account balance as maintained pursuant to Section 5.5 and the hypothetical balance of such Partner’s Capital Account computed as if it had been maintained strictly in accordance with federal income tax accounting principles.

“Book-Up Event” means an event that triggers a positive adjustment to the Capital Accounts of the Partners pursuant to Section 5.5(d).

 

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“Business Day” means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the State of Oklahoma shall not be regarded as a Business Day.

“Capital Account” means the capital account maintained for a Partner pursuant to Section 5.5. The “Capital Account” of a Partner in respect of any Partnership Interest shall be the amount that such Capital Account would be if such Partnership Interest were the only interest in the Partnership held by such Partner from and after the date on which such Partnership Interest was first issued.

“Capital Contribution” means any cash, cash equivalents or the Net Agreed Value of Contributed Property that a Partner contributes to the Partnership or that is contributed or deemed contributed to the Partnership on behalf of a Partner (including, in the case of an underwritten offering of Units, the amount of any underwriting discounts or commissions).

“Capital Improvement” means any (a) addition or improvement to the capital assets owned by any Group Member, (b) acquisition of existing, or the construction of new or the improvement or replacement of existing, capital assets (including, without limitation, crude oil or natural gas gathering systems, natural gas treatment or processing plants, natural gas liquids fractionation facilities, storage facilities, pipeline systems, equipment related to compression and/or measurement or other midstream assets or facilities) or (c) capital contribution by a Group Member to a Person that is not a Subsidiary in which a Group Member has an equity interest, or after such capital contribution will have an equity interest, to fund such Group Member’s pro rata share of the cost of the addition or improvement to or the acquisition of existing, or the construction of new or the improvement or replacement of existing, capital assets (including, without limitation, crude oil or natural gas gathering systems, natural gas treatment or processing plants, natural gas liquids fractionation facilities, storage facilities, pipeline systems, equipment related to compression and/or measurement or other midstream assets or facilities) by such Person, in each case if such addition, improvement, replacement, acquisition or construction is made to increase for a period longer than the short-term the operating capacity or operating income of the Partnership Group, in the case of clauses (a) and (b), or such Person, in the case of clause (c), from the operating capacity or operating income of the Partnership Group or such Person, as the case may be, existing immediately prior to such addition, improvement, replacement, acquisition or construction. For purposes of this definition, the short-term generally refers to a period not exceeding 12 months.

“Capital Surplus” means Available Cash distributed by the Partnership in excess of Operating Surplus, as described in Section 6.3(a).

“Carrying Value” means (a) with respect to a Contributed Property or Adjusted Property, the Agreed Value of such property reduced (but not below zero) by all depreciation, amortization and cost recovery deductions charged to the Partners’ Capital Accounts in respect of such Contributed Property or Adjusted Property, and (b) with respect to any other Partnership property, the adjusted basis of such property for federal income tax purposes, all as of the time of determination; provided that the Carrying Value of any property shall be adjusted from time to time in accordance with Sections 5.5(d)(i) and 5.5(d)(ii) and to reflect changes, additions or other adjustments to the Carrying Value for dispositions and acquisitions of Partnership properties, as deemed appropriate by the General Partner.

“Cause” means a court of competent jurisdiction has entered a final, non-appealable judgment finding the General Partner liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership.

“Certificate” means (a) a certificate (i) substantially in the form of Exhibit A to this Agreement, (ii) issued in global form in accordance with the rules and regulations of the Depositary or (iii) in such other form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more Common Units or (b) a certificate, in such form as may be adopted by the General Partner, issued by the Partnership evidencing ownership of one or more other Partnership Securities.

 

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“Certificate of Limited Partnership” means the Certificate of Limited Partnership of the Partnership filed with the Secretary of State of the State of Delaware as referenced in Section 7.2, as such Certificate of Limited Partnership may be amended, supplemented or restated from time to time.

“Chesapeake” means Chesapeake Energy Corporation, an Oklahoma corporation.

“Chesapeake Holdings” means Chesapeake Midstream Holdings, L.L.C., a Delaware limited liability company.

“Citizenship Eligibility Trigger” is defined in Section 4.9(a)(ii).

“claim” (as used in Section 7.12(c)) is defined in Section 7.12(c).

“Closing Date” means the first date on which Common Units are sold by the Partnership to the Underwriters pursuant to the provisions of the Underwriting Agreement.

“Closing Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the last sale price on such day, regular way, or in case no such sale takes place on such day, the average of the closing bid and asked prices on such day, regular way, in either case as reported in the principal consolidated transaction reporting system with respect to securities listed or admitted to trading on the principal National Securities Exchange on which the respective Limited Partner Interests are listed or admitted to trading or, if such Limited Partner Interests are not listed or admitted to trading on any National Securities Exchange, the last quoted price on such day or, if not so quoted, the average of the high bid and low asked prices on such day in the over-the-counter market, as reported by the primary reporting system then in use in relation to such Limited Partner Interests of such class, or, if on any such day such Limited Partner Interests of such class are not quoted by any such organization, the average of the closing bid and asked prices on such day as furnished by a professional market maker making a market in such Limited Partner Interests of such class selected by the General Partner, or if on any such day no market maker is making a market in such Limited Partner Interests of such class, the fair value of such Limited Partner Interests on such day as determined by the General Partner.

“Code” means the Internal Revenue Code of 1986, as amended and in effect from time to time. Any reference herein to a specific section or sections of the Code shall be deemed to include a reference to any corresponding provision of any successor law.

“Combined Interest” is defined in Section 11.3(a).

“Commences Commercial Service” shall mean the date a Capital Improvement is first put into commercial service following completion of construction, acquisition, development and testing, as applicable.

“Commission” means the United States Securities and Exchange Commission.

“Commodity Hedge Contract” means any commodity exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement that is entered into for the purpose of hedging the Partnership Group’s exposure to fluctuations in the price of hydrocarbons in their operations and not for speculative purposes.

“Common Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners, and having the rights and obligations specified with respect to Common Units in this Agreement. The term “Common Unit” does not refer to or include any Subordinated Unit prior to its conversion into a Common Unit pursuant to the terms hereof.

 

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“Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, with respect to any Quarter within the Subordination Period, the excess, if any, of (a) the Minimum Quarterly Distribution with respect to a Common Unit in respect of such Quarter over (b) the sum of all Available Cash distributed with respect to a Common Unit in respect of such Quarter pursuant to Section 6.4(a)(i).

“Conflicts Committee” means a committee of the Board of Directors of the General Partner composed entirely of two or more directors, each of whom (a) is not an officer or employee of the General Partner, (b) is not an officer, director or employee of any Affiliate of the General Partner, (c) is not a holder of any ownership interest in the General Partner or its Affiliates or the Partnership Group, other than Common Units and other awards that are granted to such director under the LTIP and (d) meets the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act and the rules and regulations of the Commission thereunder and by the National Securities Exchange on which any class of Partnership Interests is listed or admitted to trading.

“Contributed Property” means each property or other asset, in such form as may be permitted by the Delaware Act, but excluding cash, contributed to the Partnership. Once the Carrying Value of a Contributed Property is adjusted pursuant to Section 5.5(d), such property shall no longer constitute a Contributed Property, but shall be deemed an Adjusted Property.

“Contribution Agreement” means that certain [Contribution, Conveyance and Assumption] Agreement, dated as of the Closing Date, among the General Partner, the Partnership, Chesapeake Holdings, the GIP Entities and certain other parties, together with the additional conveyance documents and instruments contemplated or referenced thereunder, as such may be amended, supplemented or restated from time to time.

“Cumulative Common Unit Arrearage” means, with respect to any Common Unit, whenever issued, and as of the end of any Quarter, the excess, if any, of (a) the sum of the Common Unit Arrearages with respect to an Initial Common Unit for each of the Quarters within the Subordination Period ending on or before the last day of such Quarter over (b) the sum of any distributions theretofore made pursuant to Section 6.4(a)(ii) and the second sentence of Section 6.5 with respect to an Initial Common Unit (including any distributions to be made in respect of the last of such Quarters).

“Curative Allocation” means any allocation of an item of income, gain, deduction, loss or credit pursuant to the provisions of Section 6.1(d)(xi).

“Current Market Price” means, in respect of any class of Limited Partner Interests, as of the date of determination, the average of the daily Closing Prices per Limited Partner Interest of such class for the 20 consecutive Trading Days immediately prior to such date.

“Delaware Act” means the Delaware Revised Uniform Limited Partnership Act, 6 Del C. Section 17-101, et seq., as amended, supplemented or restated from time to time, and any successor to such statute.

“Departing General Partner” means a former General Partner from and after the effective date of any withdrawal or removal of such former General Partner pursuant to Section 11.1 or 11.2.

“Depositary” means, with respect to any Units issued in global form, The Depository Trust Company and its successors and permitted assigns.

“Disposed of Adjusted Property” has the meaning assigned to such term in Section 6.1(d)(xii)(B).

“Economic Risk of Loss” has the meaning set forth in Treasury Regulation Section 1.752-2(a).

 

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“Eligibility Certificate” is defined in Section 4.9(b).

“Eligible Holder” means a Limited Partner whose (a) federal income tax status would not, in the determination of the General Partner, have the material adverse effect described in Section 4.9(a)(i) or (b) nationality, citizenship or other related status would not, in the determination of the General Partner, create a substantial risk of cancellation or forfeiture as described in Section 4.9(a)(ii).

[“Employee Secondment Agreement” means that certain Employee Secondment Agreement, dated as of the Closing Date, between [                    ] and the General Partner, as such may be amended, supplemented and restated from time to time.]

“Estimated Incremental Quarterly Tax Amount” is defined in Section 6.9.

“Estimated Maintenance Capital Expenditures” means an estimate made in good faith by the Board of Directors (with the concurrence of the Conflicts Committee) of the average quarterly Maintenance Capital Expenditures that the Partnership will need to incur over the long term to maintain the operating capacity or operating income of the Partnership Group (including the Partnership’s proportionate share of the average quarterly Maintenance Capital Expenditures of its Subsidiaries that are not wholly owned) existing at the time the estimate is made. The Board of Directors (with the concurrence of the Conflicts Committee) will be permitted to make such estimate in any manner it determines reasonable. The estimate will be made at least annually and whenever an event occurs that is likely to result in a material adjustment to the amount of future Estimated Maintenance Capital Expenditures. The Partnership shall disclose to its Partners any change in the amount of Estimated Maintenance Capital Expenditures in its reports made in accordance with Section 8.3 to the extent not previously disclosed. Any adjustments to Estimated Maintenance Capital Expenditures shall be prospective only.

“Event of Withdrawal” is defined in Section 11.1(a).

“Expansion Capital Expenditures” means cash expenditures for Acquisitions or Capital Improvements, and shall not include Maintenance Capital Expenditures or Investment Capital Expenditures. Expansion Capital Expenditures shall include interest (and related fees) on debt incurred to finance the construction of a Capital Improvement and paid in respect of the period beginning on the date that a Group Member enters into a binding obligation to commence construction of a Capital Improvement and ending on the earlier to occur of the date that such Capital Improvement Commences Commercial Service and the date that such Capital Improvement is abandoned or disposed of. Debt incurred to fund such construction period interest payments or to fund distributions on equity issued (including incremental Incentive Distributions related thereto) to fund the construction of a Capital Improvement as described in clause (a)(iv) of the definition of Operating Surplus shall also be deemed to be debt incurred to finance the construction of a Capital Improvement. Where capital expenditures are made in part for Expansion Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

“FERC” means the Federal Energy Regulatory Commission.

“FERC Eligibility Trigger” is defined in Section 4.9(a)(i).

“Final Subordinated Units” is defined in Section 6.1(d)(x)(A).

“First Liquidation Target Amount” is defined in Section 6.1(c)(i)(D).

“First Target Distribution” means $[            ] per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the

 

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number of days in such period, and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

“Fully Diluted Weighted Average Basis” means, when calculating the number of Outstanding Units for any period, a basis that includes (1) the weighted average number of Outstanding Units plus (2) all Partnership Securities and options, rights, warrants, phantom units and appreciation rights relating to an equity interest in the Partnership (a) that are convertible into or exercisable, exchangeable or issuable for Units that are senior to or pari passu with the Subordinated Units, (b) whose conversion, exercise or exchange price is less than the Current Market Price on the date of such calculation, (c) that may be converted into or exercised or exchanged for such Units prior to or during the Quarter immediately following the end of the period for which the calculation is being made without the satisfaction of any contingency beyond the control of the holder other than the payment of consideration and the compliance with administrative mechanics applicable to such conversion, exercise or exchange and (d) that were not converted into or exercised or exchanged for such Units during the period for which the calculation is being made; provided, however, that for purposes of determining the number of Outstanding Units on a Fully Diluted Weighted Average Basis when calculating whether the Subordination Period has ended or the Subordinated Units are entitled to convert into Common Units pursuant to Section 5.7, such Partnership Securities, options, rights, warrants and appreciation rights shall be deemed to have been Outstanding Units only for the four Quarters that comprise the last four Quarters of the measurement period; provided, further, that if consideration will be paid to any Group Member in connection with such conversion, exercise or exchange, the number of Units to be included in such calculation shall be that number equal to the difference between (i) the number of Units issuable upon such conversion, exercise or exchange and (ii) the number of Units that such consideration would purchase at the Current Market Price.

“General Partner” means Chesapeake Midstream GP, L.L.C., a Delaware limited liability company, and its successors and permitted assigns that are admitted to the Partnership as general partner of the Partnership, in its capacity as general partner of the Partnership (except as the context otherwise requires).

“General Partner Interest” means the ownership interest of the General Partner in the Partnership (in its capacity as a general partner without reference to any Limited Partner Interest held by it), which is evidenced by General Partner Units, and includes any and all benefits to which the General Partner is entitled as provided in this Agreement, together with all obligations of the General Partner to comply with the terms and provisions of this Agreement.

“General Partner Unit” means a fractional part of the General Partner Interest having the rights and obligations specified with respect to the General Partner Interest. A General Partner Unit is not a Unit.

“GIP-A” means GIP-A Holding (CHK), L.P., a Delaware limited partnership.

“GIP-B” means GIP-B Holding (CHK), L.P., a Delaware limited partnership.

“GIP-C” means GIP-C Holding (CHK), L.P., a Delaware limited partnership.

“GIP Entities” means, collectively, GIP-A, GIP-B and GIP-C.

[“GP Contribution Interest” shall have the meaning assigned to it in the Contribution Agreement.]

“Gross Liability Value” means, with respect to any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i), the amount of cash that a willing assignor would pay to a willing assignee to assume such Liability in an arm’s-length transaction. The Gross Liability Value of each Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) shall be adjusted at such times as provided in this Agreement for an adjustment to Carrying Values.

 

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“Group” means a Person that with or through any of its Affiliates or Associates has any contract, arrangement, understanding or relationship for the purpose of acquiring, holding, voting (except voting pursuant to a revocable proxy or consent given to such Person in response to a proxy or consent solicitation made to 10 or more Persons), exercising investment power or disposing of any Partnership Interests with any other Person that beneficially owns, or whose Affiliates or Associates beneficially own, directly or indirectly, Partnership Interests.

“Group Member” means a member of the Partnership Group.

“Group Member Agreement” means the partnership agreement of any Group Member, other than the Partnership, that is a limited or general partnership, the limited liability company agreement of any Group Member that is a limited liability company, the certificate of incorporation and bylaws or similar organizational documents of any Group Member that is a corporation, the joint venture agreement or similar governing document of any Group Member that is a joint venture and the governing or organizational or similar documents of any other Group Member that is a Person other than a limited or general partnership, limited liability company, corporation or joint venture, as such may be amended, supplemented or restated from time to time.

“Holder” as used in Section 7.12, is defined in Section 7.12(a).

“IDR Reset Common Unit” has the meaning assigned to such term in Section 5.11(a).

“IDR Reset Election” is defined in Section 5.11(a).

“Incentive Distribution Right” means a non-voting Limited Partner Interest which will confer upon the holder thereof only the rights and obligations specifically provided in this Agreement with respect to Incentive Distribution Rights (and no other rights otherwise available to or other obligations of a holder of a Partnership Interest). Notwithstanding anything in this Agreement to the contrary, the holder of an Incentive Distribution Right shall not be entitled to vote such Incentive Distribution Right on any Partnership matter except as may otherwise be required by law.

“Incentive Distributions” means any amount of cash distributed to the holders of the Incentive Distribution Rights pursuant to Section 6.4.

“Incremental Income Taxes” is defined in Section 6.9.

“Indemnified Persons” is defined in Section 7.12(c).

“Indemnitee” means (a) any General Partner, (b) any Departing General Partner, (c) any Person who is or was an Affiliate of the General Partner or any Departing General Partner, (d) any Person who is or was a manager, managing member, director, officer, employee, agent, fiduciary or trustee of any Group Member, a General Partner, any Departing General Partner or any of their respective Affiliates, (e) any Person who is or was serving at the request of a General Partner, any Departing General Partner or any of their respective Affiliates as an officer, director, manager, managing member, employee, agent, fiduciary or trustee of another Person owing a fiduciary duty to any Group Member; provided that a Person shall not be an Indemnitee by reason of providing, on a fee-for-services basis, trustee, fiduciary or custodial services, (f) any Person who controls a General Partner or Departing General Partner and (g) any Person the General Partner designates as an “Indemnitee” for purposes of this Agreement.

“Ineligible Holder” is defined in Section 4.9(c).

“Initial Common Units” means the Common Units sold in the Initial Offering.

 

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“Initial Limited Partners” means Chesapeake Holdings and the GIP Entities (with respect to the Common Units and Subordinated Units received by them pursuant to Section 5.2), the General Partner (with respect to the Incentive Distribution Rights) and the Underwriters, in each case upon being admitted to the Partnership in accordance with Section 10.1.

“Initial Offering” means the initial offering and sale of Common Units to the public, as described in the Registration Statement.

“Initial Unit Price” means (a) with respect to the Common Units and the Subordinated Units, the initial public offering price per Common Unit at which the Underwriters offered the Common Units to the public for sale as set forth on the cover page of the prospectus included as part of the Registration Statement and first issued at or after the time the Registration Statement first became effective or (b) with respect to any other class or series of Units, the price per Unit at which such class or series of Units is initially sold by the Partnership, as determined by the General Partner, in each case adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision, combination or reorganization of Units.

“Interest Rate Hedge Contract” means any interest rate exchange, swap, forward, cap, floor, collar, option or other similar agreement or arrangement entered into for the purpose of reducing the exposure of the Partnership Group to fluctuations in interest rates in their current or anticipated financing activities and not for speculative purposes.

“Interim Capital Transactions” means the following transactions if they occur prior to the Liquidation Date: (a) borrowings, refinancings or refundings of indebtedness (other than Working Capital Borrowings and other than for items purchased on open account in the ordinary course of business) by any Group Member and sales of debt securities of any Group Member; (b) sales of equity interests of any Group Member (including the Common Units sold to the Underwriters in the Initial Offering or pursuant to the exercise of the Over-Allotment Option); (c) sales or other voluntary or involuntary dispositions of any assets of any Group Member other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements; (d) capital contributions received; and (e) corporate reorganizations or restructurings.

“Investment Capital Expenditures” means capital expenditures other than Maintenance Capital Expenditures and Expansion Capital Expenditures.

“Liability” means any liability or obligation of any nature, whether accrued, contingent or otherwise.

“Limited Partner” means, unless the context otherwise requires, each Initial Limited Partner, each additional Person that becomes a Limited Partner pursuant to the terms of this Agreement and any Departing General Partner upon the change of its status from General Partner to Limited Partner pursuant to Section 11.3, in each case, in such Person’s capacity as limited partner of the Partnership; provided, however, that when the term “Limited Partner” is used herein in the context of any vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any holder of an Incentive Distribution Right (solely with respect to its Incentive Distribution Rights and not with respect to any other Limited Partner Interest held by such Person) except as may otherwise be required by law.

“Limited Partner Interest” means the ownership interest of a Limited Partner in the Partnership, which may be evidenced by Common Units, Subordinated Units, Incentive Distribution Rights or other Partnership Securities (other than Partnership Securities evidencing the General Partner Interest) or a combination thereof or interest therein, and includes any and all benefits to which such Limited Partner is entitled as provided in this Agreement, together with all obligations of such Limited Partner to comply with the terms and provisions of this Agreement; provided, however, that when the term “Limited Partner Interest” is used herein in the context of any

 

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vote or other approval, including Articles XIII and XIV, such term shall not, solely for such purpose, include any Incentive Distribution Right except as may otherwise be required by law.

“Liquidation Date” means (a) in the case of an event giving rise to the dissolution of the Partnership of the type described in clauses (a) and (b) of the first sentence of Section 12.2, the date on which the applicable time period during which the holders of Outstanding Units have the right to elect to continue the business of the Partnership has expired without such an election being made, and (b) in the case of any other event giving rise to the dissolution of the Partnership, the date on which such event occurs.

“Liquidator” means one or more Persons selected by the General Partner to perform the functions described in Section 12.4 as liquidating trustee of the Partnership within the meaning of the Delaware Act.

“LTIP” means the Long-Term Incentive Plan of the General Partner, as may be amended, or any equity compensation plan successor thereto.

“Maintenance Capital Expenditures” means cash expenditures (including expenditures for the addition or improvement to or replacement of the capital assets owned by any Group Member or for the acquisition of existing, or the construction or development of new, capital assets, including, without limitation, gas gathering systems, natural gas treatment or processing facilities, natural gas liquids fractionation facilities, storage facilities, pipeline systems, equipment related to compression and/or measurement or other midstream assets or facilities and other related or similar midstream assets) if such expenditures are made to maintain, including for a period longer than the short-term, the operating capacity or operating income of the Partnership Group. Maintenance Capital Expenditures shall not include (a) Expansion Capital Expenditures or (b) Investment Capital Expenditures. Maintenance Capital Expenditures shall include interest (and related fees) on debt incurred and distributions on equity issued, other than equity issued on the Closing Date or the Option Closing Date, in each case, to finance the construction or development of a replacement asset and paid during the period beginning on the date that a Group Member enters into a binding obligation to commence constructing or developing a replacement asset and ending on the earlier to occur of the date that such replacement asset Commences Commercial Service and the date that such replacement asset is abandoned or disposed of. Debt incurred to pay or equity issued, other than equity issued on the Closing Date or the Option Closing Date, to fund construction or development period interest payments, or such construction or development period distributions on equity, shall also be deemed to be debt or equity, as the case may be, incurred to finance the construction or development of a replacement asset and the incremental Incentive Distributions paid relating to newly issued equity shall be deemed to be distributions paid on equity issued to finance the construction or development of a replacement asset. For purposes of this definition, the short-term generally refers to a period not exceeding 12 months.

“Merger Agreement” is defined in Section 14.1.

“Minimum Quarterly Distribution” means $[            ] per Unit per Quarter (or with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

“Minimum Volume Commitment” means, pursuant to a gas gathering or similar agreement, a commitment of a third party to deliver specified minimum volumes of natural gas to the gathering systems of the Partnership.

“National Securities Exchange” means an exchange registered with the Commission under Section 6(a) of the Securities Exchange Act (or any successor to such Section) and any other securities exchange (whether or not registered with the Commission under Section 6(a) (or successor to such Section) of the Securities Exchange Act) that the General Partner shall designate as a National Securities Exchange for purposes of this Agreement.

 

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“Net Agreed Value” means, (a) in the case of any Contributed Property, the Agreed Value of such property reduced by any Liabilities either assumed by the Partnership upon such contribution or to which such property is subject when contributed and (b) in the case of any property distributed to a Partner by the Partnership, the Partnership’s Carrying Value of such property (as adjusted pursuant to Section 5.5(d)(ii)) at the time such property is distributed, reduced by any Liability either assumed by such Partner upon such distribution or to which such property is subject at the time of distribution.

“Net Income” means, for any taxable period, the excess, if any, of the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Income shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

“Net Loss” means, for any taxable period, the excess, if any, of the Partnership’s items of loss and deduction (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period over the Partnership’s items of income and gain (other than those items taken into account in the computation of Net Termination Gain or Net Termination Loss) for such taxable period. The items included in the calculation of Net Loss shall be determined in accordance with Section 5.5(b) and shall not include any items specially allocated under Section 6.1(d); provided, that the determination of the items that have been specially allocated under Section 6.1(d) shall be made without regard to any reversal of such items under Section 6.1(d)(xii).

“Net Positive Adjustments” means, with respect to any Partner, the excess, if any, of the total positive adjustments over the total negative adjustments made to the Capital Account of such Partner pursuant to Book-Up Events and Book-Down Events.

“Net Termination Gain” means, for any taxable period, the sum, if positive, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized pursuant to Section 5.5(d); provided, however, the items included in the determination of Net Termination Gain shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Net Termination Loss” means, for any taxable period, the sum, if negative, of all items of income, gain, loss or deduction (determined in accordance with Section 5.5(b)) that are (a) recognized (i) after the Liquidation Date or (ii) upon the sale, exchange or other disposition of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (excluding any disposition to a member of the Partnership Group), or (b) deemed recognized pursuant to Section 5.5(d); provided, however, items included in the determination of Net Termination Loss shall not include any items of income, gain or loss specially allocated under Section 6.1(d).

“Nonrecourse Built-in Gain” means with respect to any Contributed Properties or Adjusted Properties that are subject to a mortgage or pledge securing a Nonrecourse Liability, the amount of any taxable gain that would be allocated to the Partners pursuant to Sections 6.2(b)(i)(A), 6.2(b)(ii)(A) and 6.2(b)(iii) if such properties were disposed of in a taxable transaction in full satisfaction of such liabilities and for no other consideration.

 

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“Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(b), are attributable to a Nonrecourse Liability.

“Nonrecourse Liability” has the meaning set forth in Treasury Regulation Section 1.752-2(b)(3).

“Notice of Election to Purchase” is defined in Section 15.1(b).

“Omnibus Agreement” means that certain Omnibus Agreement, dated as of the Closing Date, among the Partnership, the Organizational Limited Partner and Chesapeake Holdings, as such may be amended, supplemented or restated from time to time.

“Operating Expenditures” means all Partnership Group cash expenditures (or the Partnership’s proportionate share of expenditures in the case of Subsidiaries that are not wholly owned), including, but not limited to, taxes, reimbursements of expenses of the General Partner and its Affiliates, payments made in the ordinary course of business under any Interest Rate Hedge Contracts 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 shall be amortized over the life of the applicable 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 shall be included in equal quarterly installments over the remaining scheduled life of such hedge contract), officer compensation, repayment of Working Capital Borrowings, debt service payments and Estimated Maintenance Capital Expenditures, subject to the following:

(a) repayments of Working Capital Borrowings deducted from Operating Surplus pursuant to clause (b)(iii) of the definition of “Operating Surplus” shall not constitute Operating Expenditures when actually repaid;

(b) payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than Working Capital Borrowings shall not constitute Operating Expenditures; and

(c) Operating Expenditures shall not include (i) Expansion Capital Expenditures, (ii) actual Maintenance Capital Expenditures, (iii) Investment Capital Expenditures, (iv) payment of transaction expenses (including taxes) relating to Interim Capital Transactions, (v) distributions to Partners, or (vi) repurchases of Partnership Interests, other than repurchases of Partnership Interests to satisfy obligations under employee benefit plans, or reimbursements of expenses of the General Partner for such purchases. Where capital expenditures are made in part for Maintenance Capital Expenditures and in part for other purposes, the General Partner shall determine the allocation between the amounts paid for each.

“Operating Surplus” means, with respect to any period ending prior to the Liquidation Date, on a cumulative basis and without duplication,

(a) the sum of (i) $[            ] million, (ii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) for the period beginning on the Closing Date and ending on the last day of such period, but excluding cash receipts from Interim Capital Transactions and provided that cash receipts from the termination of any Interest Rate Hedge Contract or Commodity Hedge Contract prior to the expiration of its stipulated settlement or termination date shall be included in equal quarterly installments over the remaining scheduled life of such hedge contract, (iii) all cash receipts of the Partnership Group (or the Partnership’s proportionate share of cash receipts in the case of Subsidiaries that are not wholly owned) after the end of such period but on or before the date of determination of Operating Surplus with respect to such period resulting from Working Capital Borrowings, and (iv) the amount of cash distributions paid (including incremental Incentive

 

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Distributions) on equity issued, other than equity issued on the Closing Date or the Option Closing Date, to finance all or a portion of the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and paid in respect of the period beginning on the date that the Group Member enters into a binding obligation to commence the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset and ending on the earlier to occur of the date the Capital Improvement or replacement capital asset Commences Commercial Service and the date that it is abandoned or disposed of (equity issued, other than equity issued on the Closing Date or the Option Closing Date, to fund the construction period interest payments on debt incurred, or construction period distributions on equity issued, to finance the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset shall also be deemed to be equity issued to finance the construction, acquisition or improvement of a Capital Improvement or replacement of a capital asset for purposes of this clause (iv)), less

(b) the sum of (i) Operating Expenditures for the period beginning on the Closing Date and ending on the last day of such period; (ii) the amount of cash reserves established by the General Partner (or the Partnership’s proportionate share of cash reserves in the case of Subsidiaries that are not wholly owned) to provide funds for future Operating Expenditures; (iii) 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 and (iv) any cash loss realized on disposition of an Investment Capital Expenditure;

provided, however, that disbursements made (including contributions to a Group Member or disbursements on behalf of a Group Member) or cash reserves established, increased or reduced after the end of such period but on or before the date of determination of Available Cash with respect to such period shall be deemed to have been made, established, increased or reduced, for purposes of determining Operating Surplus, within such period if the General Partner so determines.

Notwithstanding the foregoing, “Operating Surplus” with respect to the Quarter in which the Liquidation Date occurs and any subsequent Quarter shall equal zero. Cash receipts from an Investment Capital Expenditure shall be treated as cash receipts only to the extent they are a return on principal, but in no event shall a return of principal be treated as cash receipts.

“Opinion of Counsel” means a written opinion of counsel (who may be regular counsel to the Partnership or the General Partner or any of its Affiliates) acceptable to the General Partner.

“Option Closing Date” means the date or dates on which any Common Units are sold by the Partnership to the Underwriters upon exercise of the Over-Allotment Option.

“Organizational Limited Partner” means Chesapeake Midstream Ventures, L.L.C., a Delaware limited liability company, in its capacity as the organizational limited partner of the Partnership pursuant to this Agreement.

“Outstanding” means, with respect to Partnership Securities, all Partnership Securities that are issued by the Partnership and reflected as outstanding on the Partnership’s books and records as of the date of determination; provided, however, that if at any time any Person or Group (other than the General Partner or its Affiliates) beneficially owns 20% or more of the Outstanding Partnership Securities of any class then Outstanding, none of the Partnership Securities owned by such Person or Group shall be voted on any matter and shall not be considered to be Outstanding when sending notices of a meeting of Limited Partners to vote on any matter (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under this Agreement, except that Partnership Securities so owned shall be considered to be Outstanding for purposes of Section 11.1(b)(iv) (such Partnership Securities shall not, however, be treated as a separate class of Partnership Securities for purposes of this Agreement or the Delaware Act); provided, further, that the foregoing limitation shall not apply to (i) any Person or Group who acquired 20% or more of the

 

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Outstanding Partnership Securities of any class then Outstanding directly from the General Partner or its Affiliates (other than the Partnership), (ii) any Person or Group who acquired 20% or more of the Outstanding Partnership Securities of any class then Outstanding directly or indirectly from a Person or Group described in clause (i) provided that, at or prior to such acquisition, the General Partner shall have notified such Person or Group in writing that such limitation shall not apply, or (iii) any Person or Group who acquired 20% or more of any Partnership Securities issued by the Partnership provided that, at or prior to such acquisition, the General Partner shall have notified such Person or Group in writing that such limitation shall not apply.

“Over-Allotment Option” means the over-allotment option granted to the Underwriters by the Partnership pursuant to the Underwriting Agreement.

“Partner Nonrecourse Debt” has the meaning set forth in Treasury Regulation Section 1.704-2(b)(4).

“Partner Nonrecourse Debt Minimum Gain” has the meaning set forth in Treasury Regulation Section 1.704-2(i)(2).

“Partner Nonrecourse Deductions” means any and all items of loss, deduction or expenditure (including any expenditure described in Section 705(a)(2)(B) of the Code) that, in accordance with the principles of Treasury Regulation Section 1.704-2(i), are attributable to a Partner Nonrecourse Debt.

“Partners” means the General Partner and the Limited Partners.

“Partnership” means Chesapeake Midstream Partners, L.P., a Delaware limited partnership.

[“Partnership Contribution Interests” shall have the meaning assigned to it in the Contribution Agreement.]

“Partnership Group” means the Partnership and its Subsidiaries treated as a single consolidated entity.

“Partnership Interest” means an interest in the Partnership, which shall include the General Partner Interest and Limited Partner Interests.

“Partnership Minimum Gain” means that amount determined in accordance with the principles of Treasury Regulation Sections 1.704-2(b)(2) and 1.704-2(d).

“Partnership Security” means any class or series of equity interest in the Partnership (but excluding any options, rights, warrants and appreciation rights relating to an equity interest in the Partnership), including Common Units, Subordinated Units and Incentive Distribution Rights.

“Percentage Interest” means as of any date of determination (a) as to the General Partner with respect to General Partner Units and as to any Unitholder with respect to Units, the product obtained by multiplying (i) 100% less the percentage applicable to clause (b) below by (ii) the quotient obtained by dividing (A) the number of General Partner Units held by the General Partner or the number of Units held by such Unitholder, as the case may be, by (B) the total number of Outstanding Units and General Partner Units, and (b) as to the holders of other Partnership Securities issued by the Partnership in accordance with Section 5.6, the percentage established as a part of such issuance. The Percentage Interest with respect to an Incentive Distribution Right shall at all times be zero.

“Person” means an individual or a corporation, firm, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

 

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“Per Unit Capital Amount” means, as of any date of determination, the Capital Account, stated on a per Unit basis, underlying any class of Units held by a Person other than the General Partner or any Affiliate of the General Partner who holds Units.

“Plan of Conversion” is defined in Section 14.1.

“Pro Rata” means (a) when used with respect to Units or any class thereof, apportioned equally among all designated Units in accordance with their relative Percentage Interests, (b) when used with respect to Partners or Record Holders, apportioned among all Partners or Record Holders in accordance with their relative Percentage Interests and (c) when used with respect to holders of Incentive Distribution Rights, apportioned equally among all holders of Incentive Distribution Rights in accordance with the relative number or percentage of Incentive Distribution Rights held by each such holder.

“Purchase Date” means the date determined by the General Partner as the date for purchase of all Outstanding Limited Partner Interests of a certain class (other than Limited Partner Interests owned by the General Partner and its Affiliates) pursuant to Article XV.

“Quarter” means, unless the context requires otherwise, a fiscal quarter of the Partnership, or, with respect to the first fiscal quarter of the Partnership that includes the Closing Date, the portion of such fiscal quarter after the Closing Date.

“Quarterly Estimated Shortfall Payment” is defined in the definition of “Adjusted Operating Surplus.”

“Recapture Income” means any gain recognized by the Partnership (computed without regard to any adjustment required by Section 734 or Section 743 of the Code) upon the disposition of any property or asset of the Partnership, which gain is characterized as ordinary income because it represents the recapture of deductions previously taken with respect to such property or asset.

“Record Date” means the date established by the General Partner or otherwise in accordance with this Agreement for determining (a) the identity of the Record Holders entitled to notice of, or to vote at, any meeting of Limited Partners or entitled to vote by ballot or give approval of Partnership action in writing without a meeting or entitled to exercise rights in respect of any lawful action of Limited Partners or (b) the identity of Record Holders entitled to receive any report or distribution or to participate in any offer.

“Record Holder” means (a) with respect to Partnership Securities of any class of Partnership Securities for which a Transfer Agent has been appointed, the Person in whose name a Partnership Security of such class is registered on the books of the Transfer Agent as of the opening of business on a particular Business Day, or (b) with respect to other classes of Partnership Interests, the Person in whose name any such other Partnership Interest is registered on the books that the General Partner has caused to be kept as of the opening of business on such Business Day.

“Redeemable Interests” means any Partnership Interests for which a redemption notice has been given, and has not been withdrawn, pursuant to Section 4.10.

“Registration Statement” means the Registration Statement on Form S-1 (Registration No. 333-164905) as it has been or as it may be amended or supplemented from time to time, filed by the Partnership with the Commission under the Securities Act to register the offering and sale of the Common Units in the Initial Offering.

“Remaining Net Positive Adjustments” means as of the end of any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the excess of (a) the Net Positive Adjustments of the

 

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Unitholders holding Common Units or Subordinated Units as of the end of such period over (b) the sum of those Partners’ Share of Additional Book Basis Derivative Items for each prior taxable period, (ii) with respect to the General Partner (as holder of the General Partner Units), the excess of (a) the Net Positive Adjustments of the General Partner as of the end of such period over (b) the sum of the General Partner’s Share of Additional Book Basis Derivative Items with respect to the General Partner Units for each prior taxable period, and (iii) with respect to the holders of Incentive Distribution Rights, the excess of (a) the Net Positive Adjustments of the holders of Incentive Distribution Rights as of the end of such period over (b) the sum of the Share of Additional Book Basis Derivative Items of the holders of the Incentive Distribution Rights for each prior taxable period.

“Required Allocations” means any allocation of an item of income, gain, loss or deduction pursuant to Section 6.1(d)(i), Section 6.1(d)(ii), Section 6.1(d)(iv), Section 6.1(d)(v), Section 6.1(d)(vi), Section 6.1(d)(vii) or Section 6.1(d)(ix).

“Reset MQD” is defined in Section 5.11(e).

“Reset Notice” is defined in Section 5.11(b).

“Residual Gain” or “Residual Loss” means any item of gain or loss, as the case may be, of the Partnership recognized for federal income tax purposes resulting from a sale, exchange or other disposition of a Contributed Property or Adjusted Property, to the extent such item of gain or loss is not allocated pursuant to Section 6.2(b)(i)(A) or Section 6.2(b)(ii)(A), respectively, to eliminate Book-Tax Disparities.

“Retained Converted Subordinated Unit” is defined in Section 5.5(c)(ii).

“Second Liquidation Target Amount” is defined in Section 6.1(c)(i)(E).

“Second Target Distribution” means $[            ] per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Section 5.11, Section 6.6 and Section 6.9.

“Securities Act” means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

“Securities Exchange Act” means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

“Share of Additional Book Basis Derivative Items” means in connection with any allocation of Additional Book Basis Derivative Items for any taxable period, (i) with respect to the Unitholders holding Common Units or Subordinated Units, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Unitholders’ Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time, (ii) with respect to the General Partner (as holder of the General Partner Units), the amount that bears the same ratio to such Additional Book Basis Derivative Items as the General Partner’s Remaining Net Positive Adjustments as of the end of such period bears to the Aggregate Remaining Net Positive Adjustment as of that time, and (iii) with respect to the Partners holding Incentive Distribution Rights, the amount that bears the same ratio to such Additional Book Basis Derivative Items as the Remaining Net Positive Adjustments of the Partners holding the Incentive Distribution Rights as of the end of such period bears to the Aggregate Remaining Net Positive Adjustments as of that time.

[“Shared Services Agreement” means that certain Shared Services Agreement, dated as of [                    ], between [                    ] and the General Partner, as such may be amended, supplemented and restated from time to time.]

 

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“Special Approval” means approval by a majority of the members of the Conflicts Committee acting in good faith.

“Subordinated Unit” means a Partnership Security representing a fractional part of the Partnership Interests of all Limited Partners and having the rights and obligations specified with respect to Subordinated Units in this Agreement. The term “Subordinated Unit” does not refer to or include a Common Unit. A Subordinated Unit that is convertible into a Common Unit shall not constitute a Common Unit until such conversion occurs.

“Subordination Period” means the period commencing on the Closing Date and ending on the first to occur of the following dates:

(a) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending June 30, 2013 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of (I) the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, and (II) the General Partner Units, in each case with respect to each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on (I) all Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and (II) the General Partner Units, in each case in respect of such periods and (B) the Adjusted Operating Surplus for each of the three consecutive, non-overlapping four-Quarter periods immediately preceding such date equaled or exceeded the sum of the Minimum Quarterly Distribution on all of the (I) Common Units, Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units and (II) General Partner Units, in each case that were Outstanding during such periods on a Fully Diluted Weighted Average Basis, and (ii) there are no Cumulative Common Unit Arrearages;

(b) the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of any Quarter beginning with the Quarter ending September 30, 2010 in respect of which (i) (A) distributions of Available Cash from Operating Surplus on each of (I) the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units, and (II) the General Partner Units, in each case with respect to the four-Quarter period immediately preceding such date equaled or exceeded 150% of the Minimum Quarterly Distribution on all of (I) the Outstanding Common Units and Subordinated Units and any other Outstanding Units that are senior or equal in right of distribution to the Subordinated Units and (II) the General Partner Units, in each case in respect of such period, and (B) the Adjusted Operating Surplus for the four-Quarter period immediately preceding such date equaled or exceeded 150% of the sum of the Minimum Quarterly Distribution on all of (I) the Common Units and Subordinated Units and any other Units that are senior or equal in right of distribution to the Subordinated Units, (II) the General Partner Units, in each case that were Outstanding during such period on a Fully Diluted Weighted Average Basis and (III) and the corresponding Incentive Distribution and (ii) there are no Cumulative Common Unit Arrearages;

(c) the first date on which there are no longer outstanding any Subordinated Units due to the conversion of Subordinated Units into Common Units pursuant to Section 5.7 or otherwise; and

(d) the date on which the General Partner is removed as general partner of the Partnership upon the requisite vote by holders of Outstanding Units under circumstances where Cause does not exist and no Units held by the General Partner and its Affiliates are voted in favor of such removal.

“Subsidiary” means, with respect to any Person, (a) a corporation of which more than 50% of the voting power of shares entitled (without regard to the occurrence of any contingency) to vote in the election of directors or other governing body of such corporation is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person or a combination thereof, (b) a partnership (whether general

 

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or limited) in which such Person or a Subsidiary of such Person is, at the date of determination, a general or limited partner of such partnership, but only if more than 50% of the partnership interests of such partnership (considering all of the partnership interests of the partnership as a single class) is owned, directly or indirectly, at the date of determination, by such Person, by one or more Subsidiaries of such Person, or a combination thereof, or (c) any other Person (other than a corporation or a partnership) in which such Person, one or more Subsidiaries of such Person, or a combination thereof, directly or indirectly, at the date of determination, has (i) at least a majority ownership interest or (ii) the power to elect or direct the election of a majority of the directors or other governing body of such Person.

“Surviving Business Entity” is defined in Section 14.2(b)(ii).

“Taxation Certification” means a properly completed certificate in such form as may be specified by the General Partner by which a Limited Partner certifies that he (and if he is a nominee holding for the account of another Person, that to the best of his knowledge such other Person) is an Eligible Holder.

“Target Distribution” means, collectively, the First Target Distribution, Second Target Distribution and Third Target Distribution.

“Third Target Distribution” means $[            ] per Unit per Quarter (or, with respect to periods of less than a full fiscal quarter, it means the product of such amount multiplied by a fraction of which the numerator is the number of days in such period, and the denominator is the total number of days in such quarter), subject to adjustment in accordance with Sections 5.11, 6.6 and 6.9.

“Trading Day” means, for the purpose of determining the Current Market Price of any class of Limited Partner Interests, a day on which the principal National Securities Exchange on which such class of Limited Partner Interests is listed or admitted to trading is open for the transaction of business or, if Limited Partner Interests of a class are not listed or admitted to trading on any National Securities Exchange, a day on which banking institutions in New York City generally are open.

“Transaction Documents” means the Chesapeake Gas Gathering Agreement, Total Gas Gathering Agreement, Additional Agreement, Contribution Agreement, Omnibus Agreement, Services Agreement, Gas Compressor Master Rental and Servicing Agreement, Employee Transfer Agreement, Employee Secondment Agreement, Shared Services Agreement, Registration Rights Agreement, Master Recoupment Netting and Setoff Agreement, Guarantee, Adherence Agreement, Trademark License Agreement, Inventory Purchase Letter, Bond Indemnity Agreement, Management Rights Agreement, Marketing Agreement and Indemnification Agreement.

“transfer” is defined in Section 4.4(a).

“Transfer Agent” means such bank, trust company or other Person (including the General Partner or one of its Affiliates) as may be appointed from time to time by the Partnership to act as registrar and transfer agent for any class of Partnership Securities; provided, that if no Transfer Agent is specifically designated for any class of Partnership Securities, the General Partner shall act in such capacity.

“Underwriter” means each Person named as an underwriter in Schedule I to the Underwriting Agreement who purchases Common Units pursuant thereto.

“Underwriting Agreement” means that certain Underwriting Agreement, dated as of [        ], 2010, among the Underwriters, the Partnership, the General Partner and other parties thereto, providing for the purchase of Common Units by the Underwriters.

“Unit” means a Partnership Security that is designated as a “Unit” and shall include Common Units and Subordinated Units but shall not include (i) General Partner Units (or the General Partner Interest represented thereby) or (ii) Incentive Distribution Rights.

 

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“Unitholders” means the holders of Units.

“Unit Majority” means (i) during the Subordination Period, at least a majority of the Outstanding Common Units (excluding Common Units owned by the General Partner and its Affiliates), voting as a class, and at least a majority of the Outstanding Subordinated Units, voting as a class, and (ii) after the end of the Subordination Period, at least a majority of the Outstanding Common Units, voting as a single class.

“Unpaid MQD” is defined in Section 6.1(c)(i)(B).

“Unrealized Gain” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the fair market value of such property as of such date (as determined under Section 5.5(d)) over (b) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date).

“Unrealized Loss” attributable to any item of Partnership property means, as of any date of determination, the excess, if any, of (a) the Carrying Value of such property as of such date (prior to any adjustment to be made pursuant to Section 5.5(d) as of such date) over (b) the fair market value of such property as of such date (as determined under Section 5.5(d)).

“Unrecovered Initial Unit Price” means at any time, with respect to a Unit, the Initial Unit Price less the sum of all distributions constituting Capital Surplus theretofore made in respect of an Initial Common Unit and any distributions of cash (or the Net Agreed Value of any distributions in kind) in connection with the dissolution and liquidation of the Partnership theretofore made in respect of an Initial Common Unit, adjusted as the General Partner determines to be appropriate to give effect to any distribution, subdivision, combination or reorganization of such Units.

“Unrestricted Person” means (a) each Indemnitee, (b) each Partner, (c) each Person who is or was a member, partner, director, officer, employee or agent of any Group Member, a General Partner or any Departing General Partner or any Affiliate of any Group Member, a General Partner or any Departing General Partner and (d) any Person the General Partner designates as an “Unrestricted Person” for purposes of this Agreement.

“U.S. GAAP” means United States generally accepted accounting principles, as in effect from time to time, consistently applied.

“Withdrawal Opinion of Counsel” is defined in Section 11.1(b).

“Working Capital Borrowings” means borrowings used solely for working capital purposes or to pay distributions to Partners, made pursuant to a credit facility, commercial paper facility or other similar financing arrangement; provided that when incurred it is the intent of the borrower to repay such borrowings within 12 months from sources other than additional Working Capital Borrowings.

Section 1.2 Construction.

Unless the context requires otherwise: (a) any pronoun used in this Agreement shall include the corresponding masculine, feminine or neuter forms; (b) references to Articles and Sections refer to Articles and Sections of this Agreement; (c) the terms “include”, “includes”, “including” or words of like import shall be deemed to be followed by the words “without limitation”; and (d) the terms “hereof”, “herein” or “hereunder” refer to this Agreement as a whole and not to any particular provision of this Agreement. The table of contents and headings contained in this Agreement are for reference purposes only, and shall not affect in any way the meaning or interpretation of this Agreement.

 

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ARTICLE II

ORGANIZATION

Section 2.1 Formation.

The General Partner and the Organizational Limited Partner have previously formed the Partnership as a limited partnership pursuant to the provisions of the Delaware Act and hereby amend and restate the original Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. in its entirety. This amendment and restatement shall become effective on the date of this Agreement. Except as expressly provided to the contrary in this Agreement, the rights, duties (including fiduciary duties), liabilities and obligations of the Partners and the administration, dissolution and termination of the Partnership shall be governed by the Delaware Act. All Partnership Interests shall constitute personal property of the owner thereof for all purposes.

Section 2.2 Name.

The name of the Partnership shall be “Chesapeake Midstream Partners, L.P.”. The Partnership’s business may be conducted under any other name or names as determined by the General Partner, including the name of the General Partner. The words “Limited Partnership,” “L.P.,” “Ltd.” or similar words or letters shall be included in the Partnership’s name where necessary for the purpose of complying with the laws of any jurisdiction that so requires. The General Partner may change the name of the Partnership at any time and from time to time and shall notify the Limited Partners of such change in the next regular communication to the Limited Partners.

Section 2.3 Registered Office; Registered Agent; Principal Office; Other Offices.

Unless and until changed by the General Partner, the registered office of the Partnership in the State of Delaware shall be located at 1209 Orange Street, Wilmington, Delaware 19801, and the registered agent for service of process on the Partnership in the State of Delaware at such registered office shall be Corporation Trust Company. The principal office of the Partnership shall be located at 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118, or such other place as the General Partner may from time to time designate by notice to the Limited Partners. The Partnership may maintain offices at such other place or places within or outside the State of Delaware as the General Partner determines to be necessary or appropriate. The address of the General Partner shall be 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118, or such other place as the General Partner may from time to time designate by notice to the Limited Partners.

Section 2.4 Purpose and Business.

The purpose and nature of the business to be conducted by the Partnership shall be to (a) engage directly in, or enter into or form, hold and dispose of any corporation, partnership, joint venture, limited liability company or other arrangement to engage indirectly in, any business activity that is approved by the General Partner, in its sole discretion, and that lawfully may be conducted by a limited partnership organized pursuant to the Delaware Act and, in connection therewith, to exercise all of the rights and powers conferred upon the Partnership pursuant to the agreements relating to such business activity, and (b) do anything necessary or appropriate to the foregoing, including the making of capital contributions or loans to a Group Member; provided, however, that the General Partner shall not cause the Partnership to engage, directly or indirectly, in any business activity that the General Partner determines would be reasonably likely to cause the Partnership to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes. To the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose or approve, and may, in its sole discretion, decline to propose or approve, the conduct by the Partnership of any business.

 

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Section 2.5 Powers.

The Partnership shall be empowered to do any and all acts and things necessary, appropriate, proper, advisable, incidental to or convenient for the furtherance and accomplishment of the purposes and business described in Section 2.4 and for the protection and benefit of the Partnership.

Section 2.6 Term.

The term of the Partnership commenced upon the filing of the Certificate of Limited Partnership in accordance with the Delaware Act and shall continue in existence until the dissolution of the Partnership in accordance with the provisions of Article XII. The existence of the Partnership as a separate legal entity shall continue until the cancellation of the Certificate of Limited Partnership as provided in the Delaware Act.

Section 2.7 Title to Partnership Assets.

Title to Partnership assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Partnership as an entity, and no Partner, individually or collectively, shall have any ownership interest in such Partnership assets or any portion thereof. Title to any or all of the Partnership assets may be held in the name of the Partnership, the General Partner, one or more of its Affiliates or one or more nominees, as the General Partner may determine. The General Partner hereby declares and warrants that any Partnership assets for which record title is held in the name of the General Partner or one or more of its Affiliates or one or more nominees shall be held by the General Partner or such Affiliate or nominee for the use and benefit of the Partnership in accordance with the provisions of this Agreement; provided, however, that the General Partner shall use reasonable efforts to cause record title to such assets (other than those assets in respect of which the General Partner determines that the expense and difficulty of conveyancing makes transfer of record title to the Partnership impracticable) to be vested in the Partnership as soon as reasonably practicable; provided, further, that, prior to the withdrawal or removal of the General Partner or as soon thereafter as practicable, the General Partner shall use reasonable efforts to effect the transfer of record title to the Partnership and, prior to any such transfer, will provide for the use of such assets in a manner satisfactory to the General Partner. All Partnership assets shall be recorded as the property of the Partnership in its books and records, irrespective of the name in which record title to such Partnership assets is held.

ARTICLE III

RIGHTS OF LIMITED PARTNERS

Section 3.1 Limitation of Liability.

The Limited Partners shall have no liability under this Agreement except as expressly provided in this Agreement or the Delaware Act.

Section 3.2 Management of Business.

No Limited Partner, in its capacity as such, shall participate in the operation, management or control (within the meaning of the Delaware Act) of the Partnership’s business, transact any business in the Partnership’s name or have the power to sign documents for or otherwise bind the Partnership. Any action taken by any Affiliate of the General Partner or any officer, director, employee, manager, member, general partner, agent or trustee of the General Partner or any of its Affiliates, or any officer, director, employee, manager, member, general partner, agent or trustee of a Group Member, in its capacity as such, shall not be deemed to be participating in the control

 

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of the business of the Partnership by a limited partner of the Partnership (within the meaning of Section 17-303(a) of the Delaware Act) and shall not affect, impair or eliminate the limitations on the liability of the Limited Partners under this Agreement.

Section 3.3 Outside Activities of the Limited Partners.

Subject to the provisions of Section 7.5, which shall continue to be applicable to the Persons referred to therein, regardless of whether such Persons shall also be Limited Partners, any Limited Partner shall be entitled to and may have business interests and engage in business activities in addition to those relating to the Partnership, including business interests and activities in direct competition with the Partnership Group. Neither the Partnership nor any of the other Partners shall have any rights by virtue of this Agreement in any business ventures of any Limited Partner.

Section 3.4 Rights of Limited Partners.

(a) In addition to other rights provided by this Agreement or by applicable law, and except as limited by Section 3.4(b), each Limited Partner shall have the right, for a purpose reasonably related to such Limited Partner’s interest as a Limited Partner in the Partnership, the reasonableness of which having been determined by the General Partner, upon reasonable written demand stating the purpose of such demand, and at such Limited Partner’s own expense:

(i) to obtain true and full information regarding the status of the business and financial condition of the Partnership;

(ii) promptly after its becoming available, to obtain a copy of the Partnership’s federal, state and local income tax returns for each year;

(iii) to obtain a current list of the name and last known business, residence or mailing address of each Partner;

(iv) to obtain a copy of this Agreement and the Certificate of Limited Partnership and all amendments thereto, together with copies of the executed copies of all powers of attorney pursuant to which this Agreement, the Certificate of Limited Partnership and all amendments thereto have been executed;

(v) to obtain true and full information regarding the amount of cash and a description and statement of the Net Agreed Value of any other Capital Contribution by each Partner and that each Partner has agreed to contribute in the future, and the date on which each became a Partner; and

(vi) to obtain such other information regarding the affairs of the Partnership as is just and reasonable.

(b) The General Partner may keep confidential from the Limited Partners, for such period of time as the General Partner deems reasonable, (i) any information that the General Partner reasonably believes to be in the nature of trade secrets or (ii) other information the disclosure of which the General Partner believes (A) is not in the best interests of the Partnership Group, (B) could damage the Partnership Group or its business or (C) that any Group Member is required by law or by agreement with any third party to keep confidential (other than agreements with Affiliates of the Partnership the primary purpose of which is to circumvent the obligations set forth in this Section 3.4).

 

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ARTICLE IV

CERTIFICATES; RECORD HOLDERS; TRANSFER OF PARTNERSHIP INTERESTS; REDEMPTION OF PARTNERSHIP INTERESTS

Section 4.1 Certificates.

Notwithstanding anything otherwise to the contrary herein, unless the General Partner shall determine otherwise in respect of some or all of any or all classes of Partnership Interests, Partnership Interests shall not be evidenced by certificates. Certificates that may be issued shall be executed on behalf of the Partnership by the Chairman of the Board, President or any Executive Vice President or Vice President and the Chief Financial Officer or the Secretary or any Assistant Secretary of the General Partner. If a Transfer Agent has been appointed for a class of Partnership Interests, no Certificate for such class of Partnership Interests shall be valid for any purpose until it has been countersigned by the Transfer Agent; provided, however, that if the General Partner elects to cause the Partnership to issue Partnership Interests of such class in global form, the Certificate shall be valid upon receipt of a certificate from the Transfer Agent certifying that the Partnership Interests have been duly registered in accordance with the directions of the Partnership. Subject to the requirements of Section 6.7(c), if Common Units are evidenced by Certificates, on or after the date on which Subordinated Units are converted into Common Units pursuant to the terms of Section 5.7, the Record Holders of such Subordinated Units (i) if the Subordinated Units are evidenced by Certificates, may exchange such Certificates for Certificates evidencing Common Units or (ii) if the Subordinated Units are not evidenced by Certificates, shall be issued Certificates evidencing Common Units.

Section 4.2 Mutilated, Destroyed, Lost or Stolen Certificates.

(a) If any mutilated Certificate is surrendered to the Transfer Agent, the appropriate officers of the General Partner on behalf of the Partnership shall execute, and the Transfer Agent shall countersign and deliver in exchange therefor, a new Certificate evidencing the same number and type of Partnership Securities as the Certificate so surrendered.

(b) The appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and the Transfer Agent shall countersign, a new Certificate in place of any Certificate previously issued if the Record Holder of the Certificate:

(i) makes proof by affidavit, in form and substance satisfactory to the General Partner, that a previously issued Certificate has been lost, destroyed or stolen;

(ii) requests the issuance of a new Certificate before the General Partner has notice that the Certificate has been acquired by a purchaser for value in good faith and without notice of an adverse claim;

(iii) if requested by the General Partner, delivers to the General Partner a bond, in form and substance satisfactory to the General Partner, with surety or sureties and with fixed or open penalty as the General Partner may direct to indemnify the Partnership, the Partners, the General Partner and the Transfer Agent against any claim that may be made on account of the alleged loss, destruction or theft of the Certificate; and

(iv) satisfies any other reasonable requirements imposed by the General Partner.

If a Limited Partner fails to notify the General Partner within a reasonable period of time after such Limited Partner has notice of the loss, destruction or theft of a Certificate, and a transfer of the Limited Partner Interests represented by the Certificate is registered before the Partnership, the General Partner or the Transfer Agent receives such notification, the Limited Partner shall be precluded from making any claim against the Partnership, the General Partner or the Transfer Agent for such transfer or for a new Certificate.

 

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(c) As a condition to the issuance of any new Certificate under this Section 4.2, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Transfer Agent) reasonably connected therewith.

Section 4.3 Record Holders.

The Partnership shall be entitled to recognize the Record Holder as the Partner with respect to any Partnership Interest and, accordingly, shall not be bound to recognize any equitable or other claim to, or interest in, such Partnership Interest on the part of any other Person, regardless of whether the Partnership shall have actual or other notice thereof, except as otherwise provided by law or any applicable rule, regulation, guideline or requirement of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading. Without limiting the foregoing, when a Person (such as a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing) is acting as nominee, agent or in some other representative capacity for another Person in acquiring and/or holding Partnership Interests, as between the Partnership on the one hand, and such other Persons on the other, such representative Person shall be (a) the Record Holder of such Partnership Interest and (b) bound by this Agreement and shall have the rights and obligations of a Partner hereunder as, and to the extent, provided herein.

Section 4.4 Transfer Generally.

(a) The term “transfer,” when used in this Agreement with respect to a Partnership Interest, shall be deemed to refer to a transaction (i) by which the General Partner assigns its General Partner Units to another Person or by which a holder of Incentive Distribution Rights assigns its Incentive Distribution Rights to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by law or otherwise or (ii) by which the holder of a Limited Partner Interest (other than an Incentive Distribution Right) assigns such Limited Partner Interest to another Person who is or becomes a Limited Partner, and includes a sale, assignment, gift, exchange or any other disposition by law or otherwise, excluding a pledge, encumbrance, hypothecation or mortgage but including any transfer upon foreclosure of any pledge, encumbrance, hypothecation or mortgage.

(b) No Partnership Interest shall be transferred, in whole or in part, except in accordance with the terms and conditions set forth in this Article IV. Any transfer or purported transfer of a Partnership Interest not made in accordance with this Article IV shall be, to the fullest extent permitted by law, null and void.

(c) Nothing contained in this Agreement shall be construed to prevent a disposition by any stockholder, member, partner or other owner of the General Partner or any Limited Partner of any or all of the shares of stock, membership interests, partnership interests or other ownership interests in the General Partner or Limited Partner and the term “transfer” shall not mean any such disposition.

Section 4.5 Registration and Transfer of Limited Partner Interests.

(a) The General Partner shall keep or cause to be kept on behalf of the Partnership a register in which, subject to such reasonable regulations as it may prescribe and subject to the provisions of Section 4.5(b), the Partnership will provide for the registration and transfer of Limited Partner Interests.

(b) The Partnership shall not recognize any transfer of Limited Partner Interests evidenced by Certificates until the Certificates evidencing such Limited Partner Interests are surrendered for registration of transfer. No charge shall be imposed by the General Partner for such transfer; provided, that as a condition to the issuance of any new Certificate under this Section 4.5, the General Partner may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed with respect thereto. Upon surrender of a

 

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Certificate for registration of transfer of any Limited Partner Interests evidenced by a Certificate, and subject to the provisions hereof, the appropriate officers of the General Partner on behalf of the Partnership shall execute and deliver, and in the case of Certificates evidencing Limited Partner Interests for which a Transfer Agent has been appointed, the Transfer Agent shall countersign and deliver, in the name of the holder or the designated transferee or transferees, as required pursuant to the holder’s instructions, one or more new Certificates evidencing the same aggregate number and type of Limited Partner Interests as was evidenced by the Certificate so surrendered.

(c) By acceptance of the transfer of any Limited Partner Interests in accordance with this Section 4.5 and except as provided in Section 4.9, each transferee of a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement.

(d) Subject to (i) the foregoing provisions of this Section 4.5, (ii) Section 4.3, (iii) Section 4.8, (iv) with respect to any class or series of Limited Partner Interests, the provisions of any statement of designations or an amendment to this Agreement establishing such class or series, (v) any contractual provisions binding on any Limited Partner and (vi) provisions of applicable law including the Securities Act, Limited Partner Interests (other than the Incentive Distribution Rights) shall be freely transferable.

(e) The General Partner and its Affiliates shall have the right at any time to transfer their Subordinated Units and Common Units (whether issued upon conversion of the Subordinated Units or otherwise) to one or more Persons.

Section 4.6 Transfer of the General Partner’s General Partner Interest.

(a) Subject to Section 4.6(c) below, prior to June 30, 2020, the General Partner shall not transfer all or any part of its General Partner Interest to a Person unless such transfer (i) has been approved by the prior written consent or vote of the holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) or (ii) is of all, but not less than all, of its General Partner Interest to (A) an Affiliate of the General Partner (other than an individual) or (B) another Person (other than an individual) in connection with the merger or consolidation of the General Partner with or into such other Person or the transfer by the General Partner of all or substantially all of its assets to such other Person.

(b) Subject to Section 4.6(c) below, on or after June 30, 2020, the General Partner may at its option transfer all or any part of its General Partner Interest without Unitholder approval.

(c) Notwithstanding anything herein to the contrary, no transfer by the General Partner of all or any part of its General Partner Interest to another Person shall be permitted unless (i) the transferee agrees to assume the rights and duties of the General Partner under this Agreement and to be bound by the provisions of this Agreement, (ii) the Partnership receives an Opinion of Counsel that such transfer would not result in the loss of limited liability under the Delaware Act of any Limited Partner or cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed) and (iii) such transferee also agrees to purchase all (or the appropriate

 

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portion thereof, if applicable) of the partnership or membership interest held by the General Partner as the general partner or managing member, if any, of each other Group Member. In the case of a transfer pursuant to and in compliance with this Section 4.6, the transferee or successor (as the case may be) shall, subject to compliance with the terms of Section 10.2, be admitted to the Partnership as the General Partner effective immediately prior to the transfer of the General Partner Interest, and the business of the Partnership shall continue without dissolution.

Section 4.7 Transfer of Incentive Distribution Rights.

Prior to June 30, 2020, a holder of Incentive Distribution Rights may only transfer any or all of the Incentive Distribution Rights held by such holder without any consent of the Unitholders to (a) an Affiliate of such holder (other than an individual), or (b) another Person (other than an individual) in connection with (i) the merger or consolidation of such holder of Incentive Distribution Rights with or into such other Person, (ii) the transfer by such holder of all or substantially all of its assets to such other Person, (iii) the sale of all the ownership interests in such holder or (iv) the pledge, encumbrance, hypothecation or mortgage of the Incentive Distribution Rights in favor a Person providing bona fide debt financing to such holder as security or collateral for such debt financing and the transfer of Incentive Distribution Rights in connection with the exercise of any remedy of such Person in connection therewith, provided, that such holder entered into such debt financing transaction in good faith for a valid purpose other than the intent to circumvent the restrictions on transfer of Incentive Distribution Rights that would otherwise have applied. Any other transfer of the Incentive Distribution Rights prior to June 30, 2020 shall require the prior approval of holders of at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates). On or after June 30, 2020, the General Partner or any other holder of Incentive Distribution Rights may transfer any or all of its Incentive Distribution Rights without Unitholder approval. Notwithstanding anything herein to the contrary, (i) the transfer of Common Units issued pursuant to Section 5.11 shall not be treated as a transfer of all or any part of the Incentive Distribution Rights and (ii) no transfer of Incentive Distribution Rights to another Person shall be permitted unless the transferee agrees to be bound by the provisions of this Agreement; provided, that no such agreement shall be required for the pledge, encumbrance, hypothecation or mortgage of the incentive distribution rights.

Section 4.8 Restrictions on Transfers.

(a) Except as provided in Section 4.8(d) below, but notwithstanding the other provisions of this Article IV, no transfer of any Partnership Interests shall be made if such transfer would (i) violate the then applicable federal or state securities laws or rules and regulations of the Commission, any state securities commission or any other governmental authority with jurisdiction over such transfer, (ii) terminate the existence or qualification of the Partnership under the laws of the jurisdiction of its formation, or (iii) cause the Partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed).

(b) The General Partner may impose restrictions on the transfer of Partnership Interests if it determines, with the advice of counsel, that such restrictions are necessary or advisable to avoid a significant risk of the Partnership becoming taxable as a corporation or otherwise becoming taxable as an entity for federal income tax purposes. The General Partner may impose such restrictions by amending this Agreement; provided, however, that any amendment that would result in the delisting or suspension of trading of any class of Limited Partner Interests on the principal National Securities Exchange on which such class of Limited Partner Interests is then listed or admitted to trading must be approved, prior to such amendment being effected, by the holders of at least a majority of the Outstanding Limited Partner Interests of such class.

(c) The transfer of a Subordinated Unit that has converted into a Common Unit shall be subject to the restrictions imposed by Section 6.7.

 

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(d) Nothing contained in this Article IV, or elsewhere in this Agreement, shall preclude the settlement of any transactions involving Partnership Interests entered into through the facilities of any National Securities Exchange on which such Partnership Interests are listed or admitted to trading.

(e) Each certificate evidencing Partnership Interests shall bear a conspicuous legend in substantially the following form:

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE CHESAPEAKE MIDSTREAM PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). CHESAPEAKE MIDSTREAM GP, L.L.C., THE GENERAL PARTNER OF CHESAPEAKE MIDSTREAM PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

Section 4.9 Eligibility Certificates; Ineligible Holders.

(a) If at any time the General Partner determines, with the advice of counsel, that

(i) the Partnership’s status other than as an association taxable as a corporation for U.S. federal income tax purposes or the failure of the Partnership otherwise to be subject to an entity-level tax for U.S. federal, state or local income tax purposes, coupled with the tax status (or lack of proof of the federal income tax status) of one or more Limited Partners, has or will reasonably likely have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership that are subject to rate regulation by FERC (a “FERC Eligibility Trigger”), or

(ii) any Group Member is subject to any federal, state or local law or regulation that would create a substantial risk of cancellation or forfeiture of any property in which the Group Member has an interest based on the nationality, citizenship or other related status of a Limited Partner (a “Citizenship Eligibility Trigger”);

then, the General Partner may adopt such amendments to this Agreement as it determines to be necessary or advisable to (x) in the case of a FERC Eligibility Trigger, obtain such proof of the federal income tax status of the Limited Partners and, to the extent relevant, their beneficial owners, as the General Partner determines to be necessary to establish those Limited Partners whose federal income tax status does not or would not have a material adverse effect on the maximum applicable rate that can be charged to customers by Subsidiaries of the Partnership that are subject to rate regulation by FERC or (y) in the case of a Citizenship Eligibility Trigger, obtain such proof of the nationality, citizenship or other related status (or, if the General Partner is a nominee

 

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holding for the account of another Person, the nationality, citizenship or other related status of such Person) of the Limited Partner as the General Partner determines to be necessary to establish and those Limited Partners whose status as a Limited Partner does not or would not subject any Group Member to a significant risk of cancellation or forfeiture of any of its properties or interests therein.

(b) Such amendments may include provisions requiring all Limited Partners to certify as to their (and their beneficial owners’) status as Eligible Holders upon demand and on a regular basis, as determined by the General Partner, and may require transferees of Units to so certify prior to being admitted to the Partnership as a Limited Partner (any such required certificate, an “Eligibility Certificate”).

(c) Such amendments may provide that any Limited Partner who fails to furnish to the General Partner within a reasonable period requested proof of its (and its beneficial owners’) status as an Eligible Holder or if upon receipt of such Eligibility Certificate or other requested information the General Partner determines that a Limited Partner is not an Eligible Holder (such a Limited Partner an “Ineligible Holder”), the Limited Partner Interests owned by such Limited Partner shall be subject to redemption in accordance with the provisions of Section 4.10. In addition, the General Partner shall be substituted for all Limited Partners that are Ineligible Holder as the Limited Partner in respect of the Ineligible Holder’s Limited Partner Interests.

(d) The General Partner shall, in exercising voting rights in respect of Limited Partner Interests held by it on behalf of Ineligible Holders, distribute the votes in the same ratios as the votes of Limited Partners (including the General Partner and its Affiliates) in respect of Limited Partner Interests other than those of Ineligible Holders are cast, either for, against or abstaining as to the matter.

(e) Upon dissolution of the Partnership, an Ineligible Holder shall have no right to receive a distribution in kind pursuant to Section 12.4 but shall be entitled to the cash equivalent thereof, and the Partnership shall provide cash in exchange for an assignment of the Ineligible Holder’s share of any distribution in kind. Such payment and assignment shall be treated for Partnership purposes as a purchase by the Partnership from the Ineligible Holder of his Limited Partner Interest (representing his right to receive his share of such distribution in kind).

(f) At any time after he can and does certify that he has become an Eligible Holder, an Ineligible Holder may, upon application to the General Partner, request that with respect to any Limited Partner Interests of such Ineligible Holder not redeemed pursuant to Section 4.10, such Ineligible Holder be admitted as a Limited Partner, and upon approval of the General Partner, such Ineligible Holder shall be admitted as a Limited Partner and shall no longer constitute an Ineligible Holder and the General Partner shall cease to be deemed to be the Limited Partner in respect of the Ineligible Holder’s Limited Partner Interests.

Section 4.10 Redemption of Partnership Interests of Ineligible Holders.

(a) If at any time a Limited Partner fails to furnish an Eligibility Certification or other information requested within a reasonable period of time specified in amendments adopted pursuant to Section 4.9, or if upon receipt of such Eligibility Certification or other information the General Partner determines, with the advice of counsel, that a Limited Partner is an Ineligible Holder, the Partnership may, unless the Limited Partner establishes to the satisfaction of the General Partner that such Limited Partner is not an Ineligible Holder or has transferred his Limited Partner Interests to a Person who is an Eligible Holder and who furnishes an Eligibility Certification to the General Partner prior to the date fixed for redemption as provided below, redeem the Limited Partner Interest of such Limited Partner as follows:

(i) The General Partner shall, not later than the 30th day before the date fixed for redemption, give notice of redemption to the Limited Partner, at his last address designated on the records of the Partnership

 

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or the Transfer Agent, by registered or certified mail, postage prepaid. The notice shall be deemed to have been given when so mailed. The notice shall specify the Redeemable Interests, the date fixed for redemption, the place of payment, that payment of the redemption price will be made upon redemption of the Redeemable Interests (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender of the Certificate evidencing the Redeemable Interests and that on and after the date fixed for redemption no further allocations or distributions to which the Limited Partner would otherwise be entitled in respect of the Redeemable Interests will accrue or be made.

(ii) The aggregate redemption price for Redeemable Interests shall be an amount equal to the Current Market Price (the date of determination of which shall be the date fixed for redemption) of Limited Partner Interests of the class to be so redeemed multiplied by the number of Limited Partner Interests of each such class included among the Redeemable Interests. The redemption price shall be paid, as determined by the General Partner, in cash or by delivery of a promissory note of the Partnership in the principal amount of the redemption price, bearing interest at the rate of [    ]% annually and payable in three equal annual installments of principal together with accrued interest, commencing one year after the redemption date.

(iii) The Limited Partner or his duly authorized representative shall be entitled to receive the payment for the Redeemable Interests at the place of payment specified in the notice of redemption on the redemption date (or, if later in the case of Redeemable Interests evidenced by Certificates, upon surrender by or on behalf of the Limited Partner or Transferee at the place specified in the notice of redemption, of the Certificate evidencing the Redeemable Interests, duly endorsed in blank or accompanied by an assignment duly executed in blank).

(iv) After the redemption date, Redeemable Interests shall no longer constitute issued and Outstanding Limited Partner Interests.

(b) The provisions of this Section 4.10 shall also be applicable to Limited Partner Interests held by a Limited Partner as nominee of a Person determined to be other than an Eligible Holder.

(c) Nothing in this Section 4.10 shall prevent the recipient of a notice of redemption from transferring his Limited Partner Interest before the redemption date if such transfer is otherwise permitted under this Agreement. Upon receipt of notice of such a transfer, the General Partner shall withdraw the notice of redemption, provided the transferee of such Limited Partner Interest certifies to the satisfaction of the General Partner that he is an Eligible Holder. If the transferee fails to make such certification, such redemption shall be effected from the transferee on the original redemption date.

ARTICLE V

CAPITAL CONTRIBUTIONS AND ISSUANCE OF PARTNERSHIP INTERESTS

Section 5.1 Organizational Contributions.

In connection with the formation of the Partnership under the Delaware Act, the General Partner made an initial Capital Contribution to the Partnership in the amount of $20.00 in exchange for a General Partner Interest equal to a 2% Percentage Interest and has been admitted as the General Partner of the Partnership. The Organizational Limited Partner made an initial Capital Contribution to the Partnership in the amount of $980.00 in exchange for a Limited Partner Interest equal to a 98% Percentage Interest and has been admitted as a Limited Partner of the Partnership. As of the Closing Date, and effective with the admission of another Limited Partner to the Partnership, the interests of the General Partner and the Organizational Limited Partner shall be redeemed as provided in the Contribution Agreement and the initial Capital Contributions of (i) the Organizational Limited Partner and (ii) the General Partner shall thereupon be refunded. Ninety-eight percent and two percent of any

 

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interest or other profit that may have resulted from the investment or other use of such initial Capital Contributions shall be allocated and distributed to the Organizational Limited Partner, and the balance thereof shall be allocated and distributed to the General Partner, respectively.

Section 5.2 Contributions by the General Partner and its Affiliates.

(a) On the Closing Date and pursuant to the Contribution Agreement: (i) the General Partner shall contribute to the Partnership, as a Capital Contribution, the [GP Contribution Interest], in exchange for (A) [                    ] General Partner Units representing a continuation of its General Partner Interest equal to a 2% Percentage Interest, subject to all of the rights, privileges and duties of the General Partner under this Agreement, and (B) the Incentive Distribution Rights; (ii) Chesapeake Holdings shall contribute to the Partnership, as a Capital Contribution, the [Partnership Contribution Interests] in exchange for [                    ] Common Units and [                    ] Subordinated Units; (iii) GIP-A shall contribute to the Partnership, as a Capital Contribution, the [Partnership Contribution Interests] in exchange for [                    ] Common Units and [                    ] Subordinated Units; (iv) GIP-B shall contribute to the Partnership, as a Capital Contribution, the [Partnership Contribution Interests] in exchange for [                    ] Common Units and [                    ] Subordinated Units; and (v) GIP-C shall contribute to the Partnership, as a Capital Contribution, the [Partnership Contribution Interests] in exchange for [                    ] Common Units and [                    ] Subordinated Units.

(b) Upon the issuance of any additional Limited Partner Interests by the Partnership (other than the Common Units issued in the Initial Offering and the Common Units and Subordinated Units issued pursuant to Section 5.2(a) but including the Option Units), the General Partner may, in exchange for a proportionate number of General Partner Units, make additional Capital Contributions in an amount equal to the product obtained by multiplying (i) the quotient determined by dividing (A) the General Partner’s Percentage Interest by (B) 100 less the General Partner’s Percentage Interest times (ii) the amount contributed to the Partnership by the Limited Partners in exchange for such additional Limited Partner Interests. Except as set forth in Article XII, the General Partner shall not be obligated to make any additional Capital Contributions to the Partnership.

Section 5.3 Contributions by Initial Limited Partners.

(a) On the Closing Date and pursuant to the Underwriting Agreement, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(b) Upon the exercise, if any, of the Over-Allotment Option, each Underwriter shall contribute cash to the Partnership in exchange for the issuance by the Partnership of Common Units to each Underwriter, all as set forth in the Underwriting Agreement.

(c) No Limited Partner will be required to make any additional Capital Contribution to the Partnership pursuant to this Agreement.

Section 5.4 Interest and Withdrawal.

No interest shall be paid by the Partnership on Capital Contributions. No Partner shall be entitled to the withdrawal or return of its Capital Contribution, except to the extent, if any, that distributions made pursuant to this Agreement or upon liquidation of the Partnership may be considered as such by law and then only to the extent provided for in this Agreement. Except to the extent expressly provided in this Agreement, no Partner shall have priority over any other Partner either as to the return of Capital Contributions or as to profits, losses or distributions. Any such return shall be a compromise to which all Partners agree within the meaning of Section 17-502(b) of the Delaware Act.

 

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Section 5.5 Capital Accounts.

(a) The Partnership shall maintain for each Partner (or a beneficial owner of Partnership Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method acceptable to the General Partner) owning a Partnership Interest a separate Capital Account with respect to such Partnership Interest in accordance with the rules of Treasury Regulation Section 1.704-1(b)(2)(iv). Such Capital Account shall be increased by (i) the amount of all Capital Contributions made to the Partnership with respect to such Partnership Interest and (ii) all items of Partnership income and gain (including income and gain exempt from tax) computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1, and decreased by (x) the amount of cash or Net Agreed Value of all actual and deemed distributions of cash or property made with respect to such Partnership Interest and (y) all items of Partnership deduction and loss computed in accordance with Section 5.5(b) and allocated with respect to such Partnership Interest pursuant to Section 6.1.

(b) For purposes of computing the amount of any item of income, gain, loss or deduction which is to be allocated pursuant to Article VI and is to be reflected in the Partners’ Capital Accounts, the determination, recognition and classification of any such item shall be the same as its determination, recognition and classification for federal income tax purposes (including any method of depreciation, cost recovery or amortization used for that purpose), provided, that:

(i) Solely for purposes of this Section 5.5, the Partnership shall be treated as owning directly its proportionate share (as determined by the General Partner based upon the provisions of the applicable Group Member Agreement) of all property owned by (x) any other Group Member that is classified as a partnership for federal income tax purposes and (y) any other partnership, limited liability company, unincorporated business or other entity classified as a partnership for federal income tax purposes of which a Group Member is, directly or indirectly, a partner, member or other equityholder.

(ii) All fees and other expenses incurred by the Partnership to promote the sale of (or to sell) a Partnership Interest that can neither be deducted nor amortized under Section 709 of the Code, if any, shall, for purposes of Capital Account maintenance, be treated as an item of deduction at the time such fees and other expenses are incurred and shall be allocated among the Partners pursuant to Section 6.1.

(iii) Except as otherwise provided in Treasury Regulation Section 1.704-1(b)(2)(iv)(m), the computation of all items of income, gain, loss and deduction shall be made without regard to any election under Section 754 of the Code which may be made by the Partnership and, as to those items described in Section 705(a)(1)(B) or 705(a)(2)(B) of the Code, without regard to the fact that such items are not includable in gross income or are neither currently deductible nor capitalized for federal income tax purposes. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment in the Capital Accounts shall be treated as an item of gain or loss.

(iv) Any income, gain, loss or deduction attributable to the taxable disposition of any Partnership property shall be determined as if the adjusted basis of such property as of such date of disposition were equal in amount to the Partnership’s Carrying Value with respect to such property as of such date.

(v) In accordance with the requirements of Section 704(b) of the Code, any deductions for depreciation, cost recovery or amortization attributable to any Contributed Property shall be determined as if the adjusted basis of such property on the date it was acquired by the Partnership were equal to the Agreed Value of such property. Upon an adjustment pursuant to Section 5.5(d) to the Carrying Value of any Partnership property subject to depreciation, cost recovery or amortization, any further deductions for such depreciation, cost recovery or amortization attributable to such property shall be determined under the rules prescribed by

 

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Treasury Regulation Section 1.704-3(d)(2) as if the adjusted basis of such property were equal to the Carrying Value of such property immediately following such adjustment.

(vi) In the event the Gross Liability Value of any Liability of the Partnership described in Treasury Regulation Section 1.752-7(b)(3)(i) is adjusted as required by this Agreement, the amount of such adjustment shall be treated as an item of loss (if the adjustment increases the Carrying Value of such Liability of the Partnership) or an item of gain (if the adjustment decreases the Carrying Value of such Liability of the Partnership) and shall be taken into account for purposes of computing Net Income or Net Loss.

(c) (i) A transferee of a Partnership Interest shall succeed to a pro rata portion of the Capital Account of the transferor relating to the Partnership Interest so transferred.

(ii) Subject to Section 6.7(c), immediately prior to the transfer of a Subordinated Unit or of a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 by a holder thereof (other than a transfer to an Affiliate unless the General Partner elects to have this subparagraph 5.5(c)(ii) apply), the Capital Account maintained for such Person with respect to its Subordinated Units or converted Subordinated Units will (A) first, be allocated to the Subordinated Units or converted Subordinated Units to be transferred in an amount equal to the product of (x) the number of such Subordinated Units or converted Subordinated Units to be transferred and (y) the Per Unit Capital Amount for a Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the transferor, regardless of whether it has retained any Subordinated Units or converted Subordinated Units (“Retained Converted Subordinated Units”). Following any such allocation, the transferor’s Capital Account, if any, maintained with respect to the retained Subordinated Units or Retained Converted Subordinated Units, if any, will have a balance equal to the amount allocated under clause (B) hereinabove, and the transferee’s Capital Account established with respect to the transferred Subordinated Units or converted Subordinated Units will have a balance equal to the amount allocated under clause (A) hereinabove.

(d) (i) Consistent with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), on an issuance of additional Partnership Interests for cash or Contributed Property, the issuance of Partnership Interests as consideration for the provision of services or the conversion of the General Partner’s Combined Interest to Common Units pursuant to Section 11.3(b), the Capital Accounts of all Partners and the Carrying Value of each Partnership property immediately prior to such issuance shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property for an amount equal to its fair market value immediately prior to such issuance and had been allocated to the Partners at such time pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to the liquidation of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss, the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to the issuance of additional Partnership Interests shall be determined by the General Partner using such method of valuation as it may adopt; provided, however, that the General Partner, in arriving at such valuation, must take fully into account the fair market value of the Partnership Interests of all Partners at such time. The General Partner shall allocate such aggregate value among the assets of the Partnership (in such manner as it determines) to arrive at a fair market value for individual properties.

(ii) In accordance with Treasury Regulation Section 1.704-1(b)(2)(iv)(f), immediately prior to any actual or deemed distribution to a Partner of any Partnership property (other than a distribution of cash that is not in redemption or retirement of a Partnership Interest), the Capital Accounts of all Partners and the Carrying Value of all Partnership property shall be adjusted upward or downward to reflect any Unrealized Gain or Unrealized Loss attributable to such Partnership property, as if such Unrealized Gain or Unrealized Loss had been recognized on an actual sale of each such property immediately prior to such distribution for

 

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an amount equal to its fair market value, and had been allocated to the Partners, at such time, pursuant to Section 6.1(c) in the same manner as any item of gain or loss actually recognized following an event giving rise to the liquidation of the Partnership would have been allocated. In determining such Unrealized Gain or Unrealized Loss the aggregate cash amount and fair market value of all Partnership assets (including cash or cash equivalents) immediately prior to a distribution shall (A) in the case of an actual distribution that is not made pursuant to Section 12.4 or in the case of a deemed distribution, be determined and allocated in the same manner as that provided in Section 5.5(d)(i) or (B) in the case of a liquidating distribution pursuant to Section 12.4, be determined and allocated by the Liquidator using such method of valuation as it may adopt.

Section 5.6 Issuances of Additional Partnership Securities.

(a) The Partnership may issue additional Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities (including as provided in Section 7.4(c)) for any Partnership purpose at any time and from time to time to such Persons for such consideration and on such terms and conditions as the General Partner shall determine, all without the approval of any Limited Partners.

(b) Each additional Partnership Security authorized to be issued by the Partnership pursuant to Section 5.6(a) or Section 7.4(c) may be issued in one or more classes, or one or more series of any such classes, with such designations, preferences, rights, powers and duties (which may be senior to existing classes and series of Partnership Securities), as shall be fixed by the General Partner, including (i) the right to share in Partnership profits and losses or items thereof; (ii) the right to share in Partnership distributions; (iii) the rights upon dissolution and liquidation of the Partnership; (iv) whether, and the terms and conditions upon which, the Partnership may or shall be required to redeem the Partnership Security (including sinking fund provisions); (v) whether such Partnership Security is issued with the privilege of conversion or exchange and, if so, the terms and conditions of such conversion or exchange; (vi) the terms and conditions upon which each Partnership Security will be issued, evidenced by certificates and assigned or transferred; (vii) the method for determining the Percentage Interest as to such Partnership Security; and (viii) the right, if any, of each such Partnership Security to vote on Partnership matters, including matters relating to the relative rights, preferences and privileges of such Partnership Security.

(c) The General Partner shall take all actions that it determines to be necessary or appropriate in connection with (i) each issuance of Partnership Securities and options, rights, warrants and appreciation rights relating to Partnership Securities pursuant to this Section 5.6 or Section 7.4(c), (ii) the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, (iii) the issuance of Common Units pursuant to Section 5.11, (iv) reflecting admission of such additional Limited Partners in the books and records of the Partnership as the Record Holder of such Limited Partner Interest and (v) all additional issuances of Partnership Securities. The General Partner shall determine the relative rights, powers and duties of the holders of the Units or other Partnership Securities being so issued. The General Partner shall do all things necessary to comply with the Delaware Act and is authorized and directed to do all things that it determines to be necessary or appropriate in connection with any future issuance of Partnership Securities or in connection with the conversion of the Combined Interest into Units pursuant to the terms of this Agreement, including compliance with any statute, rule, regulation or guideline of any federal, state or other governmental agency or any National Securities Exchange on which the Units or other Partnership Securities are listed or admitted to trading.

(d) No fractional Units shall be issued by the Partnership.

Section 5.7 Conversion of Subordinated Units.

(a) All of the Subordinated Units shall convert into Common Units on a one-for-one basis on the first Business Day following the distribution of Available Cash to Partners pursuant to Section 6.3(a) in respect of the final Quarter of the Subordination Period.

 

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(b) Notwithstanding any other provision of this Agreement, all the then Outstanding Subordinated Units will automatically convert into Common Units on a one-for-one basis as set forth in, and pursuant to the terms of, Section 11.4.

(c) A Subordinated Unit that has converted into a Common Unit shall be subject to the provisions of Section 6.7.

Section 5.8 Limited Preemptive Right.

Except as provided in this Section 5.8 and in Section 5.2 or as otherwise provided in a separate agreement by the Partnership, no Person shall have any preemptive, preferential or other similar right with respect to the issuance of any Partnership Security, whether unissued, held in the treasury or hereafter created. The General Partner shall have the right, which it may from time to time assign in whole or in part to any of its Affiliates or the beneficial owners thereof, to purchase Partnership Securities from the Partnership whenever, and on the same terms that, the Partnership issues Partnership Securities to Persons other than the General Partner and its Affiliates or such beneficial owners, to the extent necessary to maintain the Percentage Interests of the General Partner and its Affiliates and such beneficial owners equal to that which existed immediately prior to the issuance of such Partnership Securities.

Section 5.9 Splits and Combinations.

(a) Subject to Section 5.9(d), Section 6.6 and Section 6.9 (dealing with adjustments of distribution levels), the Partnership may make a Pro Rata distribution of Partnership Securities to all Record Holders or may effect a subdivision or combination of Partnership Securities so long as, after any such event, each Partner shall have the same Percentage Interest in the Partnership as before such event, and any amounts calculated on a per Unit basis (including any Common Unit Arrearage or Cumulative Common Unit Arrearage) or stated as a number of Units are proportionately adjusted retroactive to the beginning of the Partnership.

(b) Whenever such a distribution, subdivision or combination of Partnership Securities is declared, the General Partner shall select a Record Date as of which the distribution, subdivision or combination shall be effective and shall send notice thereof at least 20 days prior to such Record Date to each Record Holder as of a date not less than 10 days prior to the date of such notice. The General Partner also may cause a firm of independent public accountants selected by it to calculate the number of Partnership Securities to be held by each Record Holder after giving effect to such distribution, subdivision or combination. The General Partner shall be entitled to rely on any certificate provided by such firm as conclusive evidence of the accuracy of such calculation.

(c) Promptly following any such distribution, subdivision or combination, the Partnership may issue Certificates to the Record Holders of Partnership Securities as of the applicable Record Date representing the new number of Partnership Securities held by such Record Holders, or the General Partner may adopt such other procedures that it determines to be necessary or appropriate to reflect such changes. If any such combination results in a smaller total number of Partnership Securities Outstanding, the Partnership shall require, as a condition to the delivery to a Record Holder of such new Certificate, the surrender of any Certificate held by such Record Holder immediately prior to such Record Date.

(d) The Partnership shall not issue fractional Units upon any distribution, subdivision or combination of Units. If a distribution, subdivision or combination of Units would result in the issuance of fractional Units but for the provisions of Section 5.6(d) and this Section 5.9(d), each fractional Unit shall be rounded to the nearest whole Unit (and a 0.5 Unit shall be rounded to the next higher Unit).

 

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Section 5.10 Fully Paid and Non-Assessable Nature of Limited Partner Interests.

All Limited Partner Interests issued pursuant to, and in accordance with the requirements of, this Article V shall be fully paid and non-assessable Limited Partner Interests in the Partnership, except as such non-assessability may be affected by Section 17-607 or 17-804 of the Delaware Act.

Section 5.11 Issuance of Common Units in Connection with Reset of Incentive Distribution Rights.

(a) Subject to the provisions of this Section 5.11, the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right, at any time when there are no Subordinated Units outstanding and the Partnership has made a distribution pursuant to Section 6.4(b)(v) for each of the four most recently completed Quarters and the amount of each such distribution did not exceed Adjusted Operating Surplus for such Quarter, to make an election (the “IDR Reset Election”) to cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive their respective proportionate share of a number of Common Units (the “IDR Reset Common Units”) derived by dividing (i) the average amount of cash distributions made by the Partnership for the two full Quarters immediately preceding the giving of the Reset Notice (as defined in Section 5.11(b)) in respect of the Incentive Distribution Rights by (ii) the average of the cash distributions made by the Partnership in respect of each Common Unit for the two full Quarters immediately preceding the giving of the Reset Notice (the “Reset MQD”) (the number of Common Units determined by such quotient is referred to herein as the “Aggregate Quantity of IDR Reset Common Units”). Upon the issuance of such Common Units, the Partnership will issue to the General Partner that number of additional General Partner Units equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner immediately prior to such issuance by (B) a percentage equal to 100% less such Percentage Interest by (y) the number of such Common Units, and the General Partner shall not be obligated to make any additional Capital Contribution to the Partnership in exchange for such issuance. The making of the IDR Reset Election in the manner specified in Section 5.11(b) shall cause the Minimum Quarterly Distribution and the Target Distributions to be reset in accordance with the provisions of Section 5.11(e) and, in connection therewith, the holder or holders of the Incentive Distribution Rights will become entitled to receive Common Units and General Partner Units on the basis specified above, without any further approval required by the General Partner or the Unitholders, at the time specified in Section 5.11(c) unless the IDR Reset Election is rescinded pursuant to Section 5.11(d).

(b) To exercise the right specified in Section 5.11(a), the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall deliver a written notice (the “Reset Notice”) to the Partnership. Within 10 Business Days after the receipt by the Partnership of such Reset Notice, as the case may be, the Partnership shall deliver a written notice to the holder or holders of the Incentive Distribution Rights of the Partnership’s determination of the aggregate number of Common Units which each holder of Incentive Distribution Rights will be entitled to receive.

(c) The holder or holders of the Incentive Distribution Rights will be entitled to receive the Aggregate Quantity of IDR Reset Common Units and related additional General Partner Units on the fifteenth Business Day after receipt by the Partnership of the Reset Notice; provided, however, that the issuance of Common Units to the holder or holders of the Incentive Distribution Rights shall not occur prior to the approval of the listing or admission for trading of such Common Units by the principal National Securities Exchange upon which the Common Units are then listed or admitted for trading if any such approval is required pursuant to the rules and regulations of such National Securities Exchange.

 

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(d) If the principal National Securities Exchange upon which the Common Units are then traded has not approved the listing or admission for trading of the Common Units to be issued pursuant to this Section 5.11 on or before the 30th calendar day following the Partnership’s receipt of the Reset Notice and such approval is required by the rules and regulations of such National Securities Exchange, then the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights) shall have the right to either rescind the IDR Reset Election or elect to receive other Partnership Securities having such terms as the General Partner may approve, with the approval of the Conflicts Committee, that will provide (i) the same economic value, in the aggregate, as the Aggregate Quantity of IDR Reset Common Units would have had at the time of the Partnership’s receipt of the Reset Notice, as determined by the General Partner, and (ii) for the subsequent conversion of such Partnership Securities into Common Units within not more than 12 months following the Partnership’s receipt of the Reset Notice upon the satisfaction of one or more conditions that are reasonably acceptable to the holder of the Incentive Distribution Rights (or, if there is more than one holder of the Incentive Distribution Rights, the holders of a majority in interest of the Incentive Distribution Rights).

(e) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution shall be adjusted at the time of the issuance of Common Units or other Partnership Securities pursuant to this Section 5.11 such that (i) the Minimum Quarterly Distribution shall be reset to equal to the Reset MQD, (ii) the First Target Distribution shall be reset to equal 115% of the Reset MQD, (iii) the Second Target Distribution shall be reset to equal to 125% of the Reset MQD and (iv) the Third Target Distribution shall be reset to equal 150% of the Reset MQD.

(f) Upon the issuance of IDR Reset Common Units pursuant to Section 5.11(a), the Capital Account maintained with respect to the Incentive Distribution Rights shall (A) first, be allocated to IDR Reset Common Units in an amount equal to the product of (x) the Aggregate Quantity of IDR Reset Common Units and (y) the Per Unit Capital Amount for an Initial Common Unit, and (B) second, any remaining balance in such Capital Account will be retained by the holder of the Incentive Distributions Rights. In the event that there is not a sufficient Capital Account associated with the Incentive Distribution Rights to allocate the full Per Unit Capital Amount for an Initial Common Unit to the IDR Reset Common Units in accordance with clause (A) of this Section 5.11(f), the IDR Reset Common Units shall be subject to Sections 6.1(d)(x)(B) and (C).

ARTICLE VI

ALLOCATIONS AND DISTRIBUTIONS

Section 6.1 Allocations for Capital Account Purposes.

For purposes of maintaining the Capital Accounts and in determining the rights of the Partners among themselves, the Partnership’s items of income, gain, loss and deduction (computed in accordance with Section 5.5(b)) shall be allocated among the Partners in each taxable period as provided herein below.

(a) Net Income. Net Income for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Income for such taxable period shall be allocated as follows:

(i) First, to the General Partner until the aggregate Net Income allocated to the General Partner pursuant to this Section 6.1(a)(i) for the current taxable period and all previous taxable periods is equal to the aggregate Net Losses allocated to the General Partner pursuant to Section 6.1(b)(ii) for all previous taxable periods; and

 

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(ii) Second, the balance, if any, to the General Partner and the Unitholders, in accordance with their respective Percentage Interests;

(b) Net Losses. Net Losses for each taxable period and all items of income, gain, loss and deduction taken into account in computing Net Losses for such taxable period shall be allocated as follows:

(i) First, to the General Partner and the Unitholders, in accordance with their respective Percentage Interests; provided, that Net Losses shall not be allocated pursuant to this Section 6.1(b)(i) to the extent that such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit balance in its Adjusted Capital Account); and

(ii) Second, the balance, if any, to the General Partner;

(c) Net Termination Gains and Losses. Net Termination Gain or Net Termination Loss (including a pro rata part of each item of income, gain, loss and deduction taken into account in computing Net Termination Gain or Net Termination Loss) for such taxable period shall be allocated in the manner set forth in this Section 6.1(c). All allocations under this Section 6.1(c) shall be made after Capital Account balances have been adjusted by all other allocations provided under this Section 6.1 and after all distributions of Available Cash provided under Section 6.4 and Section 6.5 have been made; provided, however, that solely for purposes of this Section 6.1(c), Capital Accounts shall not be adjusted for distributions made pursuant to Section 12.4.

(i) Except as provided in Section 6.1(c)(iv), any Net Termination Gain (including a pro rata part of each item of income, gain, loss, and deduction taken into account in computing Net Termination Gain) shall be allocated:

(A) First, to each Partner having a deficit balance in its Capital Account, in the proportion that such deficit balance bears to the total deficit balances in the Capital Accounts of all Partners, until each such Partner has been allocated Net Termination Gain equal to any such deficit balance in its Capital Account;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(i) or Section 6.4(b)(i) with respect to such Common Unit for such Quarter (the amount determined pursuant to this clause (2) is hereinafter referred to as the “Unpaid MQD”) and (3) any then existing Cumulative Common Unit Arrearage;

(C) Third, if such Net Termination Gain is recognized (or is deemed to be recognized) prior to the conversion of the last Outstanding Subordinated Unit into a Common Unit, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (C), until the Capital Account in respect of each Subordinated Unit then Outstanding equals the sum of (1) its Unrecovered Initial Unit Price, determined for the taxable period (or portion thereof) to which this allocation of gain relates, and (2) the Minimum Quarterly Distribution for the Quarter during which the Liquidation Date occurs, reduced by any distribution pursuant to Section 6.4(a)(iii) with respect to such Subordinated Unit for such Quarter;

(D) Fourth, 100% to the General Partner and all Unitholders in accordance with their respective Percentage Interests, until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) its Unrecovered Initial Unit Price, (2) the Unpaid MQD, (3) any then existing Cumulative Common Unit Arrearage, and (4) the excess of (aa) the First Target Distribution less the

 

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Minimum Quarterly Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(iv) and Section 6.4(b)(ii) (the sum of (1), (2), (3) and (4) is hereinafter referred to as the “First Liquidation Target Amount”);

(E) Fifth, (x) to the General Partner in accordance with its Percentage Interest, (y) 13% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (E), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the First Liquidation Target Amount, and (2) the excess of (aa) the Second Target Distribution less the First Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(v) and Section 6.4(b)(iii) (the sum of (1) and (2) is hereinafter referred to as the “Second Liquidation Target Amount”);

(F) Sixth, (x) to the General Partner in accordance with its Percentage Interest, (y) 23% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (F), until the Capital Account in respect of each Common Unit then Outstanding is equal to the sum of (1) the Second Liquidation Target Amount, and (2) the excess of (aa) the Third Target Distribution less the Second Target Distribution for each Quarter of the Partnership’s existence over (bb) the cumulative per Unit amount of any distributions of Available Cash that is deemed to be Operating Surplus made pursuant to Section 6.4(a)(vi) and Section 6.4(b)(iv); and

(G) Finally, (x) to the General Partner in accordance with its Percentage Interest, (y) 48% to the holders of the Incentive Distribution Rights, Pro Rata, and (z) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (x) and (y) of this clause (G).

(ii) Except as otherwise provided by Section 6.1(c)(iii) any Net Termination Loss (including a pro rata part of each item of income, gain, loss, and deduction taken into account in determining Net Termination Loss) shall be allocated:

(A) First, if Subordinated Units remain Outstanding, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Subordinated Units, in proportion to the positive Capital Accounts in respect of such Subordinated Units, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (A), until the Capital Account in respect of each Subordinated Unit then Outstanding has been reduced to zero;

(B) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to all Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the percentage applicable to subclause (x) of this clause (B) until the Capital Account in respect of each Unit then Outstanding has been reduced to zero;

(C) Third, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(ii)(C) to the extent such allocation would cause any Unitholder to have a deficit balance in its Adjusted Capital Account (or decrease any existing deficit in its Adjusted Capital Account); and

(D) Fourth, the balance, if any, 100% to the General Partner.

(iii) Any Net Termination Loss deemed recognized pursuant to Section 5.5(d) prior to a Liquidation Date shall be allocated:

(A) First, to the General Partner and the Unitholders, Pro Rata; provided that Net Termination Loss shall not be allocated pursuant to this Section 6.1(c)(iii)(A) to the extent such allocation would

 

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cause any Unitholder to have a deficit balance in its Adjusted Capital Account at the end of such taxable period (or increase any existing deficit in its Adjusted Capital Account); and

(B) The balance, if any, to the General Partner.

(iv) If a Net Termination Loss has been allocated pursuant to Section 6.1(c)(iii), any subsequent Net Termination Gain is deemed recognized pursuant to Section 5.5(d) prior to a Liquidation Date shall be allocated:

(A) First, to the General Partner until the aggregate Net Termination Gain allocated to the General Partner pursuant to this Section 6.1(c)(iv)(A) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(B);

(B) Second, to the General Partner and the Unitholders, Pro Rata until the aggregate Net Termination Gain allocated pursuant to this Section 6.1(c)(iv)(B) is equal to the aggregate Net Termination Loss previously allocated pursuant to Section 6.1(c)(iii)(A); and

(C) The balance, if any, pursuant to the provisions of Section 6.1(c)(i).

(d) Special Allocations. Notwithstanding any other provision of this Section 6.1, the following special allocations shall be made for such taxable period:

(i) Partnership Minimum Gain Chargeback. Notwithstanding any other provision of this Section 6.1, if there is a net decrease in Partnership Minimum Gain during any Partnership taxable period, each Partner shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), 1.704-2(g)(2) and 1.704-2(j)(2)(i), or any successor provision. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d) with respect to such taxable period (other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii)). This Section 6.1(d)(i) is intended to comply with the Partnership Minimum Gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

(ii) Chargeback of Partner Nonrecourse Debt Minimum Gain. Notwithstanding the other provisions of this Section 6.1 (other than Section 6.1(d)(i)), except as provided in Treasury Regulation Section 1.704-2(i)(4), if there is a net decrease in Partner Nonrecourse Debt Minimum Gain during any Partnership taxable period, any Partner with a share of Partner Nonrecourse Debt Minimum Gain at the beginning of such taxable period shall be allocated items of Partnership income and gain for such period (and, if necessary, subsequent periods) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(i)(4) and 1.704-2(j)(2)(ii), or any successor provisions. For purposes of this Section 6.1(d), each Partner’s Adjusted Capital Account balance shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Section 6.1(d), other than Section 6.1(d)(i) and other than an allocation pursuant to Section 6.1(d)(vi) and Section 6.1(d)(vii), with respect to such taxable period. This Section 6.1(d)(ii) is intended to comply with the chargeback of items of income and gain requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

(iii) Priority Allocations.

(A) If the amount of cash or the Net Agreed Value of any property distributed (except cash or property distributed pursuant to Section 12.4) to any Unitholder with respect to its Units for a taxable period is greater (on a per Unit basis) than the amount of cash or the Net Agreed Value of property distributed to the other Unitholders with respect to their Units (on a per Unit basis), then (1) there shall be allocated gross income and gain to each Unitholder receiving such greater cash or property distribution until the aggregate amount of such items allocated pursuant to this Section 6.1(d)(iii)(A)

 

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for the current taxable period and all previous taxable periods is equal to the product of (aa) the amount by which the distribution (on a per Unit basis) to such Unitholder exceeds the distribution (on a per Unit basis) to the Unitholders receiving the smallest distribution and (bb) the number of Units owned by the Unitholder receiving the greater distribution; and (2) the General Partner shall be allocated gross income and gain in an aggregate amount equal to the product obtained by multiplying (aa) the quotient determined by dividing (x) the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs by (y) the sum of 100 less the General Partner’s Percentage Interest at the time in which the greater cash or property distribution occurs times (bb) the sum of the amounts allocated in clause (1) above.

(B) After the application of Section 6.1(d)(iii)(A), all or any portion of the remaining items of Partnership gross income or gain for the taxable period, if any, shall be allocated (1) to the holders of Incentive Distribution Rights, Pro Rata, until the aggregate amount of such items allocated to the holders of Incentive Distribution Rights pursuant to this Section 6.1(d)(iii)(B) for the current taxable period and all previous taxable periods is equal to the cumulative amount of all Incentive Distributions made to the holders of Incentive Distribution Rights from the Closing Date to a date 45 days after the end of the current taxable period; and (2) to the General Partner an amount equal to the product of (aa) an amount equal to the quotient determined by dividing (x) the General Partner’s Percentage Interest by (y) the sum of 100 less the General Partner’s Percentage Interest times (bb) the sum of the amounts allocated in clause (1) above.

(iv) Qualified Income Offset. In the event any Partner unexpectedly receives any adjustments, allocations or distributions described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), 1.704-1(b)(2)(ii)(d)(5), or 1.704-1(b)(2)(ii)(d)(6), items of Partnership gross income and gain shall be specially allocated to such Partner in an amount and manner sufficient to eliminate, to the extent required by the Treasury Regulations promulgated under Section 704(b) of the Code, the deficit balance, if any, in its Adjusted Capital Account created by such adjustments, allocations or distributions as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Section 6.1(d)(i) or Section 6.1(d)(ii).

(v) Gross Income Allocations. In the event any Partner has a deficit balance in its Capital Account at the end of any Partnership taxable period in excess of the sum of (A) the amount such Partner is required to restore pursuant to the provisions of this Agreement and (B) the amount such Partner is deemed obligated to restore pursuant to Treasury Regulation Sections 1.704-2(g) and 1.704-2(i)(5), such Partner shall be specially allocated items of Partnership gross income and gain in the amount of such excess as quickly as possible; provided, that an allocation pursuant to this Section 6.1(d)(v) shall be made only if and to the extent that such Partner would have a deficit balance in its Capital Account as adjusted after all other allocations provided for in this Section 6.1 have been tentatively made as if this Section 6.1(d)(v) were not in this Agreement.

(vi) Nonrecourse Deductions. Nonrecourse Deductions for any taxable period shall be allocated to the Partners in accordance with their respective Percentage Interests. If the General Partner determines that the Partnership’s Nonrecourse Deductions should be allocated in a different ratio to satisfy the safe harbor requirements of the Treasury Regulations promulgated under Section 704(b) of the Code, the General Partner is authorized, upon notice to the other Partners, to revise the prescribed ratio to the numerically closest ratio that does satisfy such requirements.

(vii) Partner Nonrecourse Deductions. Partner Nonrecourse Deductions for any taxable period shall be allocated 100% to the Partner that bears the Economic Risk of Loss with respect to the Partner Nonrecourse Debt to which such Partner Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Partner bears the Economic Risk of Loss with respect to a Partner Nonrecourse Debt, such Partner Nonrecourse Deductions attributable thereto shall be allocated between or among such Partners in accordance with the ratios in which they share such Economic Risk of Loss.

 

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(viii) Nonrecourse Liabilities. For purposes of Treasury Regulation Section 1.752-3(a)(3), the Partners agree that Nonrecourse Liabilities of the Partnership in excess of the sum of (A) the amount of Partnership Minimum Gain and (B) the total amount of Nonrecourse Built-in Gain shall be allocated among the Partners in accordance with their respective Percentage Interests.

(ix) Code Section 754 Adjustments. To the extent an adjustment to the adjusted tax basis of any Partnership asset pursuant to Section 734(b) or 743(b) of the Code is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m), to be taken into account in determining Capital Accounts, the amount of such adjustment to the Capital Accounts shall be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such item of gain or loss shall be specially allocated to the Partners in a manner consistent with the manner in which their Capital Accounts are required to be adjusted pursuant to such Section of the Treasury Regulations.

(x) Economic Uniformity.

(A) At the election of the General Partner with respect to any taxable period ending upon, or after, the termination of the Subordination Period, all or a portion of the remaining items of Partnership gross income or gain for such taxable period, after taking into account allocations pursuant to Section 6.1(d)(iii), shall be allocated 100% to each Partner holding Subordinated Units that are Outstanding as of the termination of the Subordination Period (“Final Subordinated Units”) in the proportion of the number of Final Subordinated Units held by such Partner to the total number of Final Subordinated Units then Outstanding, until each such Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such Final Subordinated Units to an amount that after taking into account the other allocations of income, gain, loss and deduction to be made with respect to such taxable period will equal the product of (A) the number of Final Subordinated Units held by such Partner and (B) the Per Unit Capital Amount for a Common Unit. The purpose of this allocation is to establish uniformity between the Capital Accounts underlying Final Subordinated Units and the Capital Accounts underlying Common Units held by Persons other than the General Partner and its Affiliates immediately prior to the conversion of such Final Subordinated Units into Common Units. This allocation method for establishing such economic uniformity will be available to the General Partner only if the method for allocating the Capital Account maintained with respect to the Subordinated Units between the transferred and retained Subordinated Units pursuant to Section 5.5(c)(ii) does not otherwise provide such economic uniformity to the Final Subordinated Units.

(B) With respect to an event triggering an adjustment to the Carrying Value of Partnership property pursuant to Section 5.5(d) during any taxable period of the Partnership ending upon, or after, the issuance of IDR Reset Common Units pursuant to Section 5.11, after the application of Section 6.1(d)(x)(A), any Unrealized Gains and Unrealized Losses shall be allocated among the Partners in a manner that to the nearest extent possible results in the Capital Accounts maintained with respect to such IDR Reset Common Units issued pursuant to Section 5.11 equaling the product of (A) the Aggregate Quantity of IDR Reset Common Units and (B) the Per Unit Capital Amount for an Initial Common Unit.

(C) With respect to any taxable period during which an IDR Reset Unit is transferred to any Person who is not an Affiliate of the transferor, all or a portion of the remaining items of Partnership gross income or gain for such taxable period shall be allocated 100% to the transferor Partner of such transferred IDR Reset Unit until such transferor Partner has been allocated an amount of gross income or gain that increases the Capital Account maintained with respect to such transferred IDR Reset Unit to an amount equal to the Per Unit Capital Amount for an Initial Common Unit.

 

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(xi) Curative Allocation.

(A) Notwithstanding any other provision of this Section 6.1, other than the Required Allocations, the Required Allocations shall be taken into account in making the Agreed Allocations so that, to the extent possible, the net amount of items of gross income, gain, loss and deduction allocated to each Partner pursuant to the Required Allocations and the Agreed Allocations, together, shall be equal to the net amount of such items that would have been allocated to each such Partner under the Agreed Allocations had the Required Allocations and the related Curative Allocation not otherwise been provided in this Section 6.1. In exercising its discretion under this Section 6.1(d)(xi)(A), the General Partner may take into account future required allocations that, although not yet made, are likely to offset other required allocations previously made. Allocations pursuant to this Section 6.1(d)(xi)(A) shall only be made with respect to Required Allocations to the extent the General Partner determines that such allocations will otherwise be inconsistent with the economic agreement among the Partners.

(B) The General Partner shall, with respect to each taxable period, (1) apply the provisions of Section 6.1(d)(xi)(A) in whatever order is most likely to minimize the economic distortions that might otherwise result from the Required Allocations, and (2) divide all allocations pursuant to Section 6.1(d)(xi)(A) among the Partners in a manner that is likely to minimize such economic distortions.

(xii) Corrective and Other Allocations. In the event of any allocation of Additional Book Basis Derivative Items or any Book-Down Event or any recognition of a Net Termination Loss, the following rules shall apply:

(A) Except as provided in Section 6.1(d)(xii)(B), in the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof) with respect to any Partnership property, the General Partner shall allocate such Additional Book Basis Derivative Items (1) to (aa) the holders of Incentive Distribution Rights and (bb) the General Partner in the same manner that the Unrealized Gain or Unrealized Loss attributable to such property is allocated pursuant to Section 5.5(d) and (2) to all Unitholders, Pro Rata, to the extent that the Unrealized Gain or Unrealized Loss attributable to such property is allocated to any Unitholders pursuant to Section 5.5(d).

(B) In the case of any allocation of Additional Book Basis Derivative Items (other than an allocation of Unrealized Gain or Unrealized Loss under Section 5.5(d) hereof) as a result of a sale or other taxable disposition of any Partnership asset that is an Adjusted Property (“Disposed of Adjusted Property”), the General Partner shall allocate (1) additional items of gross income and gain (aa) away from the holders of Incentive Distribution Rights and (bb) to the Unitholders, or (2) additional items of deduction and loss (aa) away from the Unitholders and (bb) to the holders of Incentive Distribution Rights, to the extent that the Additional Book Basis Derivative Items allocated to the Unitholders exceed their Share of Additional Book Basis Derivative Items with respect to such Disposed of Adjusted Property. For this purpose, the Unitholders shall be treated as being allocated Additional Book Basis Derivative Items to the extent that such Additional Book Basis Derivative Items have reduced the amount of income that would otherwise have been allocated to the Unitholders under this Agreement. Any allocation made pursuant to this Section 6.1(d)(xii)(B) shall be made after all of the other Agreed Allocations have been made as if this Section 6.1(d)(xii) were not in this Agreement and, to the extent necessary, shall require the reallocation of items that have been allocated pursuant to such other Agreed Allocations.

(C) In the case of any negative adjustments to the Capital Accounts of the Partners resulting from a Book-Down Event or from the recognition of a Net Termination Loss, such negative adjustment (1) shall first be allocated, to the extent of the Aggregate Remaining Net Positive Adjustments, in such a manner, as determined by the General Partner, that to the extent possible the aggregate Capital

 

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Accounts of the Partners will equal the amount that would have been the Capital Account balance of the Partners if no prior Book-Up Events had occurred, and (2) any negative adjustment in excess of the Aggregate Remaining Net Positive Adjustments shall be allocated pursuant to Section 6.1(c) hereof.

(D) In making the allocations required under this Section 6.1(d)(xii), the General Partner may apply whatever conventions or other methodology it determines will satisfy the purpose of this Section 6.1(d)(xii). Without limiting the foregoing, if an Adjusted Property is contributed by the Partnership to another entity classified as a partnership for federal income tax purposes (the “lower tier partnership”), the General Partner may make allocations similar to those described Sections 6.1(d)(xii)(A)–(C) to the extent the General Partner determines such allocations are necessary to account for the Partnership’s allocable share of income, gain, loss and deduction of the lower tier partnership that relate to the contributed Adjusted Property in a manner that is consistent with the purpose of this Section 6.1(d)(xii).

(xiii) Special Curative Allocation in Event of Liquidation Prior to End of Subordination Period. Notwithstanding any other provision of this Section 6.1 (other than the Required Allocations), if the Liquidation Date occurs prior to the conversion of the last Outstanding Subordinated Unit, then items of income, gain, loss and deduction for the taxable period that includes the Liquidation Date (and, if necessary, items arising in previous taxable periods to the extent the General Partner determines such items may be so allocated), shall be specially allocated among the Partners in the manner determined appropriate by the General Partner so as to cause, to the maximum extent possible, the Capital Account in respect of each Common Unit to equal the amount such Capital Account would have been if all prior allocations of Net Termination Gain and Net Termination Loss had been made pursuant to Section 6.1(c)(i) or Section 6.1(c)(ii), as applicable.

Section 6.2 Allocations for Tax Purposes.

(a) Except as otherwise provided herein, for federal income tax purposes, each item of income, gain, loss and deduction shall be allocated among the Partners in the same manner as its correlative item of “book” income, gain, loss or deduction is allocated pursuant to Section 6.1.

(b) In an attempt to eliminate Book-Tax Disparities attributable to a Contributed Property or Adjusted Property, items of income, gain, loss, depreciation, amortization and cost recovery deductions shall be allocated for federal income tax purposes among the Partners as follows:

(i) (A) In the case of a Contributed Property, such items attributable thereto shall be allocated among the Partners in the manner provided under Section 704(c) of the Code that takes into account the variation between the Agreed Value of such property and its adjusted basis at the time of contribution; and (B) any item of Residual Gain or Residual Loss attributable to a Contributed Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(ii) (A) In the case of an Adjusted Property, such items shall (1) first, be allocated among the Partners in a manner consistent with the principles of Section 704(c) of the Code to take into account the Unrealized Gain or Unrealized Loss attributable to such property and the allocations thereof pursuant to Section 5.5(d)(i) or Section 5.5(d)(ii), and (2) second, in the event such property was originally a Contributed Property, be allocated among the Partners in a manner consistent with Section 6.2(b)(i)(A); and (B) any item of Residual Gain or Residual Loss attributable to an Adjusted Property shall be allocated among the Partners in the same manner as its correlative item of “book” gain or loss is allocated pursuant to Section 6.1.

(iii) The General Partner shall apply the principles of Treasury Regulation Section 1.704-3(d) to eliminate Book-Tax Disparities.

 

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(c) For the proper administration of the Partnership and for the preservation of uniformity of the Limited Partner Interests (or any class or classes thereof), the General Partner shall (i) adopt such conventions as it deems appropriate in determining the amount of depreciation, amortization and cost recovery deductions; (ii) make special allocations for federal income tax purposes of income (including gross income) or deductions; and (iii) amend the provisions of this Agreement as appropriate (x) to reflect the proposal or promulgation of Treasury Regulations under Section 704(b) or Section 704(c) of the Code or (y) otherwise to preserve or achieve uniformity of the Limited Partner Interests (or any class or classes thereof). The General Partner may adopt such conventions, make such allocations and make such amendments to this Agreement as provided in this Section 6.2(c) only if such conventions, allocations or amendments would not have a material adverse effect on the Partners, the holders of any class or classes of Limited Partner Interests issued and Outstanding or the Partnership, and if such allocations are consistent with the principles of Section 704 of the Code.

(d) The General Partner may determine to depreciate or amortize the portion of an adjustment under Section 743(b) of the Code attributable to unrealized appreciation in any Adjusted Property (to the extent of the unamortized Book-Tax Disparity) using a predetermined rate derived from the depreciation or amortization method and useful life applied to the unamortized Book-Tax Disparity of such property, despite any inconsistency of such approach with Treasury Regulation Section 1.167(c)-l(a)(6) or any successor regulations thereto. If the General Partner determines that such reporting position cannot reasonably be taken, the General Partner may adopt depreciation and amortization conventions under which all purchasers acquiring Limited Partner Interests in the same month would receive depreciation and amortization deductions, based upon the same applicable rate as if they had purchased a direct interest in the Partnership’s property. If the General Partner chooses not to utilize such aggregate method, the General Partner may use any other depreciation and amortization conventions to preserve the uniformity of the intrinsic tax characteristics of any Limited Partner Interests, so long as such conventions would not have a material adverse effect on the Limited Partners or the Record Holders of any class or classes of Limited Partner Interests.

(e) In accordance with Treasury Regulation Sections 1.1245-1(e) and 1.1250-1(f), any gain allocated to the Partners upon the sale or other taxable disposition of any Partnership asset shall, to the extent possible, after taking into account other required allocations of gain pursuant to this Section 6.2, be characterized as Recapture Income in the same proportions and to the same extent as such Partners (or their predecessors in interest) have been allocated any deductions directly or indirectly giving rise to the treatment of such gains as Recapture Income.

(f) All items of income, gain, loss, deduction and credit recognized by the Partnership for federal income tax purposes and allocated to the Partners in accordance with the provisions hereof shall be determined without regard to any election under Section 754 of the Code that may be made by the Partnership; provided, however, that such allocations, once made, shall be adjusted (in the manner determined by the General Partner) to take into account those adjustments permitted or required by Sections 734 and 743 of the Code.

(g) Each item of Partnership income, gain, loss and deduction, for federal income tax purposes, shall be determined on an annual basis and prorated on a monthly basis and shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of each month; provided, however, such items for the period beginning on the Closing Date and ending on the last day of the month in which the exercise in full of the Over-Allotment Option or the expiration of the Over-Allotment Option occurs shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to trading on the first Business Day of the next succeeding month; and provided, further, that gain or loss on a sale or other disposition of any assets of the Partnership or any other extraordinary item of income or loss realized and recognized other than in the ordinary course of business, as determined by the General Partner, shall be allocated to the Partners as of the opening of the National Securities Exchange on which the Partnership Interests are listed or admitted to

 

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trading on the first Business Day of the month in which such gain or loss is recognized for federal income tax purposes. The General Partner may revise, alter or otherwise modify such methods of allocation to the extent permitted or required by Section 706 of the Code and the regulations or rulings promulgated thereunder.

(h) Allocations that would otherwise be made to a Limited Partner under the provisions of this Article VI shall instead be made to the beneficial owner of Limited Partner Interests held by a nominee in any case in which the nominee has furnished the identity of such owner to the Partnership in accordance with Section 6031(c) of the Code or any other method determined by the General Partner.

Section 6.3 Requirement and Characterization of Distributions; Distributions to Record Holders.

(a) Within 45 days following the end of each Quarter commencing with the Quarter ending on September 30, 2010, an amount equal to 100% of Available Cash with respect to such Quarter shall be distributed in accordance with this Article VI by the Partnership to Partners as of the Record Date selected by the General Partner. All amounts of Available Cash distributed by the Partnership on any date from any source shall be deemed to be Operating Surplus until the sum of all amounts of Available Cash theretofore distributed by the Partnership to the Partners pursuant to Section 6.4 equals the Operating Surplus from the Closing Date through the close of the immediately preceding Quarter. Any remaining amounts of Available Cash distributed by the Partnership on such date shall, except as otherwise provided in Section 6.5, be deemed to be “Capital Surplus.” All distributions required to be made under this Agreement shall be made subject to Sections 17-607 and 17-804 of the Delaware Act.

(b) Notwithstanding Section 6.3(a), in the event of the dissolution and liquidation of the Partnership, all cash received during or after the Quarter in which the Liquidation Date occurs, other than from Working Capital Borrowings, shall be applied and distributed solely in accordance with, and subject to the terms and conditions of, Section 12.4.

(c) The General Partner may treat taxes paid by the Partnership on behalf of, or amounts withheld with respect to, all or less than all of the Partners, as a distribution of Available Cash to such Partners.

(d) Each distribution in respect of a Partnership Interest shall be paid by the Partnership, directly or through any Transfer Agent or through any other Person or agent, only to the Record Holder of such Partnership Interest as of the Record Date set for such distribution. Such payment shall constitute full payment and satisfaction of the Partnership’s liability in respect of such payment, regardless of any claim of any Person who may have an interest in such payment by reason of an assignment or otherwise.

Section 6.4 Distributions of Available Cash from Operating Surplus.

(a) During Subordination Period. Available Cash with respect to any Quarter within the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or 6.5 shall be distributed as follows, except as otherwise contemplated by Section 5.6(b) in respect of other Partnership Securities issued pursuant thereto:

(i) First, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Common Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage existing with respect to such Quarter;

 

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(iii) Third, (x) to the General Partner in accordance with its Percentage Interest and (y) to the Unitholders holding Subordinated Units, Pro Rata, a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Subordinated Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(iv) Fourth, to the General Partner and all Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(v) Fifth, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v) until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(vi) Sixth, (A) to the General Partner in accordance with its Percentage Interest, (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vi), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

(vii) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (vii);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(a)(vii).

(b) After Subordination Period. Available Cash with respect to any Quarter after the Subordination Period that is deemed to be Operating Surplus pursuant to the provisions of Section 6.3 or Section 6.5 shall be distributed as follows, except as otherwise contemplated by Section 5.6(b) in respect of additional Partnership Securities issued pursuant thereto:

(i) First, 100% to the General Partner and the Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the Minimum Quarterly Distribution for such Quarter;

(ii) Second, 100% to the General Partner and the Unitholders, Pro Rata, until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the First Target Distribution over the Minimum Quarterly Distribution for such Quarter;

(iii) Third, (A) to the General Partner in accordance with its Percentage Interest; (B) 13% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iii), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Second Target Distribution over the First Target Distribution for such Quarter;

(iv) Fourth, (A) to the General Partner in accordance with its Percentage Interest; (B) 23% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (iv), until there has been distributed in respect of each Unit then Outstanding an amount equal to the excess of the Third Target Distribution over the Second Target Distribution for such Quarter; and

 

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(v) Thereafter, (A) to the General Partner in accordance with its Percentage Interest; (B) 48% to the holders of the Incentive Distribution Rights, Pro Rata; and (C) to all Unitholders, Pro Rata, a percentage equal to 100% less the sum of the percentages applicable to subclauses (A) and (B) of this clause (v);

provided, however, if the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution have been reduced to zero pursuant to the second sentence of Section 6.6(a), the distribution of Available Cash that is deemed to be Operating Surplus with respect to any Quarter will be made solely in accordance with Section 6.4(b)(v).

Section 6.5 Distributions of Available Cash from Capital Surplus.

Available Cash that is deemed to be Capital Surplus pursuant to the provisions of Section 6.3(a) shall be distributed, unless the provisions of Section 6.3 require otherwise, 100% to the General Partner and the Unitholders, Pro Rata, until a hypothetical holder of a Common Unit acquired on the Closing Date has received with respect to such Common Unit, during the period since the Closing Date through such date, distributions of Available Cash that are deemed to be Capital Surplus in an aggregate amount equal to the Initial Unit Price. Available Cash that is deemed to be Capital Surplus shall then be distributed (A) to the General Partner in accordance with its Percentage Interest and (B) to all Unitholders holding Common Units their Pro Rata share of a percentage equal to 100% less the General Partner’s Percentage Interest, until there has been distributed in respect of each Common Unit then Outstanding an amount equal to the Cumulative Common Unit Arrearage. Thereafter, all Available Cash shall be distributed as if it were Operating Surplus and shall be distributed in accordance with Section 6.4.

Section 6.6 Adjustment of Minimum Quarterly Distribution and Target Distribution Levels.

(a) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution, Third Target Distribution, Common Unit Arrearages and Cumulative Common Unit Arrearages shall be proportionately adjusted in the event of any distribution, combination or subdivision (whether effected by a distribution payable in Units or otherwise) of Units or other Partnership Securities in accordance with Section 5.9. In the event of a distribution of Available Cash that is deemed to be from Capital Surplus, the then applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be adjusted proportionately downward to equal the product obtained by multiplying the otherwise applicable Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, as the case may be, by a fraction of which the numerator is the Unrecovered Initial Unit Price of the Common Units immediately after giving effect to such distribution and of which the denominator is the Unrecovered Initial Unit Price of the Common Units immediately prior to giving effect to such distribution.

(b) The Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall also be subject to adjustment pursuant to Section 5.11 and Section 6.9.

Section 6.7 Special Provisions Relating to the Holders of Subordinated Units.

(a) Except with respect to the right to vote on or approve matters requiring the vote or approval of a percentage of the holders of Outstanding Common Units and the right to participate in allocations of income, gain, loss and deduction and distributions made with respect to Common Units, the holder of a Subordinated Unit shall have all of the rights and obligations of a Unitholder holding Common Units hereunder; provided, however, that immediately upon the conversion of Subordinated Units into Common Units pursuant to Section 5.7, the Unitholder holding a Subordinated Unit shall possess all of the rights and obligations of a Unitholder holding Common Units hereunder, including the right to vote as a Common Unitholder and the right to participate in

 

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allocations of income, gain, loss and deduction and distributions made with respect to Common Units; provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x)(A), 6.7(b) and 6.7(c).

(b) A Unitholder shall not be permitted to transfer a Subordinated Unit or a Subordinated Unit that has converted into a Common Unit pursuant to Section 5.7 (other than a transfer to an Affiliate) if the remaining balance in the transferring Unitholder’s Capital Account with respect to the retained Subordinated Units or Retained Converted Subordinated Units would be negative after giving effect to the allocation under Section 5.5(c)(ii)(B).

(c) The Unitholder holding a Common Unit that has resulted from the conversion of a Subordinated Unit pursuant to Section 5.7 shall not be issued a Common Unit Certificate pursuant to Section 4.1, and shall not be permitted to transfer such Common Unit to a Person that is not an Affiliate of the holder until such time as the General Partner determines, based on advice of counsel, that each such Common Unit should have, as a substantive matter, like intrinsic economic and federal income tax characteristics, in all material respects, to the intrinsic economic and federal income tax characteristics of an Initial Common Unit. In connection with the condition imposed by this Section 6.7(c), the General Partner may take whatever steps are required to provide economic uniformity to such Common Units in preparation for a transfer of such Common Units, including the application of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7(b); provided, however, that no such steps may be taken that would have a material adverse effect on the Unitholders holding Common Units.

Section 6.8 Special Provisions Relating to the Holders of Incentive Distribution Rights.

Notwithstanding anything to the contrary set forth in this Agreement, the holders of the Incentive Distribution Rights (a) shall (i) possess the rights and obligations provided in this Agreement with respect to a Limited Partner pursuant to Article III and Article VII and (ii) have a Capital Account as a Partner pursuant to Section 5.5 and all other provisions related thereto and (b) shall not (i) be entitled to vote on any matters requiring the approval or vote of the holders of Outstanding Units, except as provided by law, (ii) be entitled to any distributions other than as provided in Sections 6.4 and 12.4 or (iii) be allocated items of income, gain, loss or deduction other than as specified in this Article VI.

Section 6.9 Entity-Level Taxation.

If legislation is enacted or the interpretation of existing language is modified by a governmental authority so that a Group Member is treated as an association taxable as a corporation or is otherwise subject to an entity-level tax for federal, state or local income tax purposes, then the General Partner may, in its sole discretion, reduce the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution to take into account the amount of income taxes that are payable by reason of any such new legislation or interpretation (the “Incremental Income Taxes”), or any portion thereof selected by the General Partner, in the manner provided in this Section 6.9. If the General Partner elects to reduce the Minimum Quarterly Distribution, the First Target Distribution, the Second Target Distribution and the Third Target Distribution for any Quarter with respect to all or a portion of any Incremental Income Taxes, the General Partner shall estimate for such Quarter the Partnership Group’s aggregate liability (the “Estimated Incremental Quarterly Tax Amount”) for all such income taxes that are payable by reason of any such new legislation or interpretation; provided that any difference between such estimate and the actual tax liability for such Quarter that is owed by reason of any such new legislation or interpretation shall be taken into account in determining the Estimated Incremental Quarterly Tax Amount with respect to each Quarter in which any such difference can be determined. For each such Quarter, the Minimum Quarterly Distribution, First Target Distribution, Second Target Distribution and Third Target Distribution, shall be the product obtained by multiplying (a) the amounts therefor that are set out herein prior to the application of this Section 6.9 times (b) the quotient obtained by

 

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dividing (i) Available Cash with respect to such Quarter by (ii) the sum of Available Cash with respect to such Quarter and the Estimated Incremental Quarterly Tax Amount for such Quarter, as determined by the General Partner. For purposes of the foregoing, Available Cash with respect to a Quarter will be deemed reduced by the Estimated Incremental Quarterly Tax Amount for that Quarter.

ARTICLE VII

MANAGEMENT AND OPERATION OF BUSINESS

Section 7.1 Management.

(a) The General Partner shall conduct, direct and manage all activities of the Partnership. Except as otherwise expressly provided in this Agreement, all management powers over the business and affairs of the Partnership shall be exclusively vested in the General Partner, and no Limited Partner shall have any management power over the business and affairs of the Partnership. In addition to the powers now or hereafter granted a general partner of a limited partnership under applicable law or that are granted to the General Partner under any other provision of this Agreement, the General Partner, subject to Section 7.3, shall have full power and authority to do all things and on such terms as it determines to be necessary or appropriate to conduct the business of the Partnership, to exercise all powers set forth in Section 2.5 and to effectuate the purposes set forth in Section 2.4, including the following:

(i) the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible or exchangeable into Partnership Securities, and the incurring of any other obligations;

(ii) the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the business or assets of the Partnership;

(iii) the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the assets of the Partnership or the merger or other combination of the Partnership with or into another Person (the matters described in this clause (iii) being subject, however, to any prior approval that may be required by Section 7.3 or Article XIV);

(iv) the use of the assets of the Partnership (including cash on hand) for any purpose consistent with the terms of this Agreement, including the financing of the conduct of the operations of the Partnership Group; subject to Section 7.6(a), the lending of funds to other Persons (including other Group Members); the repayment or guarantee of obligations of any Group Member; and the making of capital contributions to any Group Member;

(v) the negotiation, execution and performance of any contracts, conveyances or other instruments (including instruments that limit the liability of the Partnership under contractual arrangements to all or particular assets of the Partnership, with the other party to the contract to have no recourse against the General Partner or its assets other than its interest in the Partnership, even if same results in the terms of the transaction being less favorable to the Partnership than would otherwise be the case);

(vi) the distribution of Partnership cash;

(vii) the selection and dismissal of employees (including employees having titles such as “president,” “vice president,” “secretary” and “treasurer”) and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

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(ix) the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other Persons (including the acquisition of interests in, and the contributions of property to, any Group Member from time to time) subject to the restrictions set forth in Section 2.4;

(x) the control of any matters affecting the rights and obligations of the Partnership, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

(xi) the indemnification of any Person against liabilities and contingencies to the extent permitted by law;

(xii) the entering into of listing agreements with any National Securities Exchange and the delisting of some or all of the Limited Partner Interests from, or requesting that trading be suspended on, any such exchange (subject to any prior approval that may be required under Section 4.8);

(xiii) the purchase, sale or other acquisition or disposition of Partnership Securities, or the issuance of options, rights, warrants and appreciation rights relating to Partnership Securities;

(xiv) the undertaking of any action in connection with the Partnership’s participation in any Group Member; and

(xv) the entering into of agreements with any of its Affiliates to render services to a Group Member or to itself in the discharge of its duties as General Partner of the Partnership.

(b) Notwithstanding any other provision of this Agreement, any Group Member Agreement, the Delaware Act or any applicable law, rule or regulation, each of the Partners and each other Person who may acquire an interest in Partnership Securities or is otherwise bound by this Agreement hereby (i) approves, ratifies and confirms the execution, delivery and performance by the parties thereto of this Agreement and the Group Member Agreement of each other Group Member, the Underwriting Agreement, the Omnibus Agreement, the Contribution Agreement and the other agreements described in or filed as exhibits to the Registration Statement that are related to the transactions contemplated by the Registration Statement (in each case other than this Agreement, without giving effect to any amendments, supplements or restatements after the date hereof); (ii) agrees that the General Partner (on its own or on behalf of the Partnership) is authorized to execute, deliver and perform the agreements referred to in clause (i) of this sentence and the other agreements, acts, transactions and matters described in or contemplated by the Registration Statement on behalf of the Partnership without any further act, approval or vote of the Partners or the other Persons who may acquire an interest in Partnership Securities or is otherwise bound by this Agreement; and (iii) agrees that the execution, delivery or performance by the General Partner, any Group Member or any Affiliate of any of them of this Agreement or any agreement authorized or permitted under this Agreement (including the exercise by the General Partner or any Affiliate of the General Partner of the rights accorded pursuant to Article XV) shall not constitute a breach by the General Partner of any duty that the General Partner may owe the Partnership or the Limited Partners or any other Persons under this Agreement (or any other agreements) or of any duty otherwise existing at law, in equity or otherwise.

Section 7.2 Certificate of Limited Partnership.

The General Partner has caused the Certificate of Limited Partnership to be filed with the Secretary of State of the State of Delaware as required by the Delaware Act. The General Partner shall use all reasonable efforts to cause to be filed such other certificates or documents that the General Partner determines to be necessary or appropriate for the formation, continuation, qualification and operation of a limited partnership (or a partnership in which the limited partners have limited liability) in the State of Delaware or any other state in which the Partnership may elect to do business or own property. To the extent the General Partner determines such action to

 

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be necessary or appropriate, the General Partner shall file amendments to and restatements of the Certificate of Limited Partnership and do all things to maintain the Partnership as a limited partnership (or a partnership or other entity in which the limited partners have limited liability) under the laws of the State of Delaware or of any other state in which the Partnership may elect to do business or own property. Subject to the terms of Section 3.4(a), the General Partner shall not be required, before or after filing, to deliver or mail a copy of the Certificate of Limited Partnership, any qualification document or any amendment thereto to any Limited Partner.

Section 7.3 Restrictions on the General Partner’s Authority.

Except as provided in Article XII and Article XIV, the General Partner may not sell, exchange or otherwise dispose of all or substantially all of the assets of the Partnership Group, taken as a whole, in a single transaction or a series of related transactions (including by way of merger, consolidation, other combination or sale of ownership interests of the Partnership’s Subsidiaries) without the approval of holders of a Unit Majority; provided, however, that this provision shall not preclude or limit the General Partner’s ability to mortgage, pledge or encumber all or substantially all of the assets of the Partnership Group and shall not apply to any forced sale of any or all of the assets of the Partnership Group pursuant to the foreclosure of, or other realization upon, any such mortgage, pledge or encumbrance.

Section 7.4 Reimbursement of the General Partner.

(a) Except as provided in this Section 7.4 and elsewhere in this Agreement, the General Partner shall not be compensated for its services as a general partner or managing member of any Group Member.

(b) The General Partner shall be reimbursed on a monthly basis, or such other basis as the General Partner may determine, for (i) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership Group (including salary, bonus, incentive compensation and other amounts paid to any Person, including Affiliates of the General Partner to perform services for the Partnership Group or for the General Partner in the discharge of its duties to the Partnership Group), and (ii) all other expenses allocable to the Partnership Group or otherwise incurred by the General Partner in connection with operating the Partnership Group’s business (including expenses allocated to the General Partner by its Affiliates). The General Partner shall determine the expenses that are allocable to the General Partner or the Partnership Group. Reimbursements pursuant to this Section 7.4 shall be in addition to any reimbursement to the General Partner as a result of indemnification pursuant to Section 7.7.

(c) The General Partner, without the approval of the Limited Partners (who shall have no right to vote in respect thereof), may propose and adopt on behalf of the Partnership employee benefit plans, employee programs and employee practices (including plans, programs and practices involving the issuance of Partnership Securities or options to purchase or rights, warrants or appreciation rights or phantom or tracking interests relating to Partnership Securities), or cause the Partnership to issue Partnership Securities in connection with, or pursuant to, any employee benefit plan, employee program or employee practice maintained or sponsored by the General Partner or any of its Affiliates, in each case for the benefit of employees and directors of the General Partner or any of its Affiliates, in respect of services performed, directly or indirectly, for the benefit of the Partnership Group. The Partnership agrees to issue and sell to the General Partner or any of its Affiliates any Partnership Securities that the General Partner or such Affiliates are obligated to provide to any employees and directors pursuant to any such employee benefit plans, employee programs or employee practices. Expenses incurred by the General Partner in connection with any such plans, programs and practices (including the net cost to the General Partner or such Affiliates of Partnership Securities purchased by the General Partner or such Affiliates, from the Partnership, to fulfill options or awards under such plans, programs and practices) shall be reimbursed in accordance with Section 7.4(b). Any and all obligations of the General Partner under any employee benefit plans, employee programs or employee practices adopted by the General Partner as permitted by this

 

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Section 7.4(c) shall constitute obligations of the General Partner hereunder and shall be assumed by any successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner’s General Partner Interest pursuant to Section 4.6.

(d) The General Partner and its Affiliates may charge any member of the Partnership Group a management fee to the extent necessary to allow the Partnership Group to reduce the amount of any state franchise or income tax or any tax based upon the revenues or gross margin of any member of the Partnership Group if the tax benefit produced by the payment of such management fee or fees exceeds the amount of such fee or fees.

Section 7.5 Outside Activities.

(a) The General Partner, for so long as it is the General Partner of the Partnership (i) agrees that its sole business will be to act as a general partner or managing member, as the case may be, of the Partnership and any other partnership or limited liability company of which the Partnership is, directly or indirectly, a partner or member and to undertake activities that are ancillary or related thereto (including being a limited partner in the Partnership) and (ii) shall not engage in any business or activity or incur any debts or liabilities except in connection with or incidental to (A) its performance as general partner or managing member, if any, of one or more Group Members or as described in or contemplated by the Registration Statement, (B) the acquiring, owning or disposing of debt or equity securities in any Group Member or (C) the guarantee of, and mortgage, pledge, or encumbrance of any or all of its assets in connection with, any indebtedness of any Affiliate of the General Partner.

(b) Each Unrestricted Person (other than the General Partner) shall have the right to engage in businesses of every type and description and other activities for profit and to engage in and possess an interest in other business ventures of any and every type or description, whether in businesses engaged in or anticipated to be engaged in by any Group Member, independently or with others, including business interests and activities in direct competition with the business and activities of any Group Member, and none of the same shall constitute a breach of this Agreement or any duty otherwise existing at law, in equity or otherwise, to any Group Member or any Partner. None of any Group Member, any Limited Partner or any other Person shall have any rights by virtue of this Agreement, any Group Member Agreement, or the partnership relationship established hereby in any business ventures of any Unrestricted Person.

(c) Subject to the terms of Sections 7.5(a) and (b), but otherwise notwithstanding anything to the contrary in this Agreement, (i) the engaging in competitive activities by any Unrestricted Person (other than the General Partner) in accordance with the provisions of this Section 7.5 is hereby approved by the Partnership and all Partners, (ii) it shall be deemed not to be a breach of any fiduciary duty or any other obligation of any type whatsoever of the General Partner or any other Unrestricted Person for the Unrestricted Persons (other than the General Partner) to engage in such business interests and activities in preference to or to the exclusion of the Partnership and (iii) the Unrestricted Persons shall have no obligation hereunder or as a result of any duty otherwise existing at law, in equity or otherwise, to present business opportunities to the Partnership. Notwithstanding anything to the contrary in this Agreement, the doctrine of corporate opportunity, or any analogous doctrine, shall not apply to any Unrestricted Person (including the General Partner). No Unrestricted Person (including the General Partner) who acquires knowledge of a potential transaction, agreement, arrangement or other matter that may be an opportunity for the Partnership, shall have any duty to communicate or offer such opportunity to the Partnership, and such Unrestricted Person (including the General Partner) shall not be liable to the Partnership, to any Limited Partner or any other Person for breach of any fiduciary or other duty by reason of the fact that such Unrestricted Person (including the General Partner) pursues or acquires for itself, directs such opportunity to another Person or does not communicate such opportunity or information to the Partnership; provided such Unrestricted Person does not engage in such business or activity as a result of or using confidential or proprietary information provided by or on behalf of the Partnership to such Unrestricted Person.

 

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(d) The General Partner and each of its Affiliates may acquire Units or other Partnership Securities in addition to those acquired on the Closing Date and, except as otherwise provided in this Agreement, shall be entitled to exercise, at their option, all rights relating to all Units and/or other Partnership Securities acquired by them. The term “Affiliates” when used for purposes of this Section 7.5(d) with respect to the General Partner shall not include any Group Member.

(e) Notwithstanding anything to the contrary in this Agreement, (i) to the extent that any provision of this Agreement purports or is interpreted to have the effect of restricting the fiduciary duties that might otherwise, as a result of Delaware or other applicable law, be owed by the General Partner to the Partnership and its Limited Partners, or to constitute a waiver or consent by the Limited Partners to any such restriction, such provisions shall be deemed to have been approved by the Partners and (ii) nothing in this Agreement shall limit or otherwise affect any separate contractual obligations outside of this Agreement of any Person (including any Unrestricted Person) to the Partnership or any of its Affiliates, including under any of the Transaction Documents.

Section 7.6 Loans from the General Partner; Loans or Contributions from the Partnership or Group Members.

(a) The General Partner or any of its Affiliates may lend to any Group Member, and any Group Member may borrow from the General Partner or any of its Affiliates, funds needed or desired by the Group Member for such periods of time and in such amounts as the General Partner may determine; provided, however, that in any such case the lending party may not charge the borrowing party interest at a rate greater than the rate that would be charged the borrowing party or impose terms less favorable to the borrowing party than would be charged or imposed on the borrowing party by unrelated lenders on comparable loans made on an arm’s-length basis (without reference to the lending party’s financial abilities or guarantees), all as determined by the General Partner. The borrowing party shall reimburse the lending party for any costs (other than any additional interest costs) incurred by the lending party in connection with the borrowing of such funds. For purposes of this Section 7.6(a) and Section 7.6(b), the term “Group Member” shall include any Affiliate of a Group Member that is controlled by the Group Member.

(b) The Partnership may lend or contribute to any Group Member, and any Group Member may borrow from the Partnership, funds on terms and conditions determined by the General Partner. No Group Member may lend funds to the General Partner or any of its Affiliates (other than another Group Member).

(c) No borrowing by any Group Member or the approval thereof by the General Partner shall be deemed to constitute a breach of any duty hereunder or otherwise existing at law, in equity or otherwise, of the General Partner or its Affiliates to the Partnership or the Limited Partners by reason of the fact that the purpose or effect of such borrowing is directly or indirectly to (i) enable distributions to the General Partner or its Affiliates (including in their capacities as Limited Partners) to exceed the General Partner’s Percentage Interest of the total amount distributed to all Partners or (ii) hasten the expiration of the Subordination Period or the conversion of any Subordinated Units into Common Units.

Section 7.7 Indemnification.

(a) To the fullest extent permitted by law but subject to the limitations expressly provided in this Agreement, all Indemnitees shall be indemnified and held harmless by the Partnership from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened pending or completed claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, and whether formal or informal and including appeals, in which any Indemnitee may be involved, or is threatened to be involved, as a party or otherwise, by reason of its status as an Indemnitee; provided, that the Indemnitee shall not be indemnified and held harmless if there has been a final and non-appealable judgment entered by a court of

 

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competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was unlawful; provided, further, no indemnification pursuant to this Section 7.7 shall be available to the General Partner or its Affiliates (other than a Group Member) with respect to its or their obligations incurred pursuant to the Underwriting Agreement, the Omnibus Agreement, the Contribution Agreement, [Employee Secondment Agreement], [Shared Services Agreement], [                    ] or [                    ] (other than obligations incurred by the General Partner on behalf of the Partnership). Any indemnification pursuant to this Section 7.7 shall be made only out of the assets of the Partnership, it being agreed that the General Partner shall not be personally liable for such indemnification and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate such indemnification.

(b) To the fullest extent permitted by law, expenses (including legal fees and expenses) incurred by an Indemnitee who is indemnified pursuant to Section 7.7(a) in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Partnership prior to a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter for which the Indemnitee is seeking indemnification pursuant to this Section 7.7, the Indemnitee is not entitled to be indemnified upon receipt by the Partnership of any undertaking by or on behalf of the Indemnitee to repay such amount if it shall be ultimately determined that the Indemnitee is not entitled to be indemnified as authorized by this Section 7.7.

(c) The indemnification provided by this Section 7.7 shall be in addition to any other rights to which an Indemnitee may be entitled under any agreement, pursuant to any vote of the holders of Outstanding Limited Partner Interests, as a matter of law, in equity or otherwise, both as to actions in the Indemnitee’s capacity as an Indemnitee and as to actions in any other capacity (including any capacity under the Underwriting Agreement), and shall continue as to an Indemnitee who has ceased to serve in such capacity and shall inure to the benefit of the heirs, successors, assigns and administrators of the Indemnitee.

(d) The Partnership may purchase and maintain (or reimburse the General Partner or its Affiliates for the cost of) insurance, on behalf of the General Partner, its Affiliates and such other Persons as the General Partner shall determine, against any liability that may be asserted against, or expense that may be incurred by, such Person in connection with the Partnership’s activities or such Person’s activities on behalf of the Partnership, regardless of whether the Partnership would have the power to indemnify such Person against such liability under the provisions of this Agreement.

(e) For purposes of this Section 7.7, the Partnership shall be deemed to have requested an Indemnitee to serve as fiduciary of an employee benefit plan whenever the performance by it of its duties to the Partnership also imposes duties on, or otherwise involves services by, it to the plan or participants or beneficiaries of the plan; excise taxes assessed on an Indemnitee with respect to an employee benefit plan pursuant to applicable law shall constitute “fines” within the meaning of Section 7.7(a); and action taken or omitted by it with respect to any employee benefit plan in the performance of its duties for a purpose reasonably believed by it to be in the best interest of the participants and beneficiaries of the plan shall be deemed to be for a purpose that is in the best interests of the Partnership.

(f) In no event may an Indemnitee subject the Limited Partners to personal liability by reason of the indemnification provisions set forth in this Agreement.

(g) An Indemnitee shall not be denied indemnification in whole or in part under this Section 7.7 because the Indemnitee had an interest in the transaction with respect to which the indemnification applies if the transaction was otherwise permitted by the terms of this Agreement.

(h) The provisions of this Section 7.7 are for the benefit of the Indemnitees and their heirs, successors, assigns, executors and administrators and shall not be deemed to create any rights for the benefit of any other Persons.

 

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(i) No amendment, modification or repeal of this Section 7.7 or any provision hereof shall in any manner terminate, reduce or impair the right of any past, present or future Indemnitee to be indemnified by the Partnership, nor the obligations of the Partnership to indemnify any such Indemnitee under and in accordance with the provisions of this Section 7.7 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.8 Liability of Indemnitees.

(a) Notwithstanding anything to the contrary set forth in this Agreement, no Indemnitee shall be liable for monetary damages to the Partnership, the Limited Partners, or any other Persons who have acquired interests in the Partnership Securities, for losses sustained or liabilities incurred as a result of any act or omission of an Indemnitee unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that, in respect of the matter in question, the Indemnitee acted in bad faith or engaged in fraud, willful misconduct or, in the case of a criminal matter, acted with knowledge that the Indemnitee’s conduct was criminal.

(b) Subject to its obligations and duties as General Partner set forth in Section 7.1(a), the General Partner may exercise any of the powers granted to it by this Agreement and perform any of the duties imposed upon it hereunder either directly or by or through its agents, and the General Partner shall not be responsible for any misconduct or negligence on the part of any such agent appointed by the General Partner in good faith.

(c) To the extent that, at law or in equity, an Indemnitee has duties (including fiduciary duties) and liabilities relating thereto to the Partnership or to the Partners, the General Partner and any other Indemnitee acting in connection with the Partnership’s business or affairs shall not be liable to the Partnership or to any Partner for its good faith reliance on the provisions of this Agreement.

(d) Any amendment, modification or repeal of this Section 7.8 or any provision hereof shall be prospective only and shall not in any way affect the limitations on the liability of the Indemnitees under this Section 7.8 as in effect immediately prior to such amendment, modification or repeal with respect to claims arising from or relating to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when such claims may arise or be asserted.

Section 7.9 Resolution of Conflicts of Interest; Standards of Conduct and Modification of Duties.

(a) Unless otherwise expressly provided in this Agreement or any Group Member Agreement, whenever a potential conflict of interest exists or arises between the General Partner or any of its Affiliates, on the one hand, and the Partnership, any Group Member or any Partner, on the other, any resolution or course of action by the General Partner or its Affiliates in respect of such conflict of interest shall be permitted and deemed approved by all Partners, and shall not constitute a breach of this Agreement, of any Group Member Agreement, of any agreement contemplated herein or therein, or of any duty stated or implied by law or equity, if the resolution or course of action in respect of such conflict of interest is (i) approved by Special Approval, (ii) approved by the vote of a majority of the Common Units (excluding Common Units owned by the General Partner and its Affiliates), (iii) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (iv) fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). The General Partner shall be authorized but not required in connection with its resolution of such conflict of interest to seek Special Approval or Unitholder approval of such resolution, and the General Partner may also adopt a resolution or course of action that has not received Special Approval or Unitholder approval. If Special Approval is sought, then it shall be presumed that, in making its decision, the

 

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Conflicts Committee acted in good faith, and if neither Special Approval nor Unitholder approval is sought and the Board of Directors determines that the resolution or course of action taken with respect to a conflict of interest satisfies either of the standards set forth in clauses (iii) or (iv) above, then it shall be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by any Limited Partner or by or on behalf of such Limited Partner or any other Limited Partner or the Partnership challenging such approval, the Person bringing or prosecuting such proceeding shall have the burden of overcoming such presumption. Notwithstanding anything to the contrary in this Agreement or any duty otherwise existing at law or equity, the existence of the conflicts of interest described in the Registration Statement are hereby approved by all Partners and shall not constitute a breach of this Agreement, of any Group Member Agreement or of any duty otherwise existing at law, in equity or otherwise.

(b) Whenever the General Partner, or any committee of the Board of Directors (including the Conflicts Committee), makes a determination or takes or declines to take any other action, or any of its Affiliates causes the General Partner to do so, in its capacity as the general partner of the Partnership as opposed to in its individual capacity, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then, unless another express standard is provided for in this Agreement, the General Partner, such committee or such Affiliates causing the General Partner to do so, shall make such determination or take or decline to take such other action in good faith and shall not be subject to any other or different standards (including fiduciary standards) imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. In order for a determination or other action to be in “good faith” for purposes of this Agreement, the Person or Persons making such determination or taking or declining to take such other action must believe that the determination or other action is in the best interests of the Partnership.

(c) Whenever the General Partner makes a determination or takes or declines to take any other action, or any of its Affiliates causes it to do so, in its individual capacity as opposed to in its capacity as the general partner of the Partnership, whether under this Agreement, any Group Member Agreement or any other agreement contemplated hereby or otherwise, then the General Partner, or such Affiliates causing it to do so, are entitled, to the fullest extent permitted by law, to make such determination or to take or decline to take such other action free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner, and any other Person bound by this Agreement, and the General Partner, or such Affiliates causing it to do so, shall not, to the fullest extent permitted by law, be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. By way of illustration and not of limitation, whenever the phrase, “at the option of the General Partner,” “in its sole discretion” or some variation of those phrases, are used in this Agreement, it indicates that the General Partner is acting in its individual capacity. For the avoidance of doubt, whenever the General Partner votes or transfers its Partnership Interests, or refrains from voting or transferring its Partnership Interests, it shall be acting in its individual capacity.

(d) The General Partner’s organizational documents may provide that determinations to take or decline to take any action in its individual, rather than representative, capacity may or shall be determined by its members, if the General Partner is a limited liability company, stockholders, if the General Partner is a corporation, or the members or stockholders of the General Partner’s general partner, if the General Partner is a partnership.

(e) Notwithstanding anything to the contrary in this Agreement, the General Partner and its Affiliates shall have no duty or obligation, express or implied, to (i) sell or otherwise dispose of any asset of the Partnership Group other than in the ordinary course of business or (ii) permit any Group Member to use any facilities or assets of the General Partner and its Affiliates, except as may be provided in contracts entered into from time to time specifically dealing with such use. Any determination by the General Partner or any of its Affiliates to enter into such contracts shall be in its sole discretion.

 

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(f) Except as expressly set forth in this Agreement or the Delaware Act, neither the General Partner nor any other Indemnitee shall have any duties or liabilities, including fiduciary duties, to the Partnership or any Limited Partner and the provisions of this Agreement, to the extent that they restrict, eliminate or otherwise modify the duties and liabilities, including fiduciary duties, of the General Partner or any other Indemnitee otherwise existing at law or in equity, are agreed by the Partners to replace such other duties and liabilities of the General Partner or such other Indemnitee.

(g) The Unitholders hereby authorize the General Partner, on behalf of the Partnership as a partner or member of a Group Member, to approve of actions by the general partner or managing member of such Group Member similar to those actions permitted to be taken by the General Partner pursuant to this Section 7.9.

Section 7.10 Other Matters Concerning the General Partner.

(a) The General Partner may rely upon, and shall be protected in acting or refraining from acting upon, any resolution, certificate, statement, instrument, opinion, report, notice, request, consent, order, bond, debenture or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties.

(b) The General Partner may consult with legal counsel, accountants, appraisers, management consultants, investment bankers and other consultants and advisers selected by it, and any act taken or omitted to be taken in reliance upon the advice or opinion (including an Opinion of Counsel) of such Persons as to matters that the General Partner reasonably believes to be within such Person’s professional or expert competence shall be conclusively presumed to have been done or omitted in good faith and in accordance with such advice or opinion.

(c) The General Partner shall have the right, in respect of any of its powers or obligations hereunder, to act through any of its duly authorized officers, a duly appointed attorney or attorneys-in-fact or the duly authorized officers of the Partnership.

Section 7.11 Purchase or Sale of Partnership Securities.

The General Partner may cause the Partnership to purchase or otherwise acquire Partnership Securities; provided that, except as permitted pursuant to Section 4.10, the General Partner may not cause any Group Member to purchase Subordinated Units during the Subordination Period. Such Partnership Securities shall be held by the Partnership as treasury securities unless they are expressly cancelled by action of an appropriate officer of the General Partner. As long as Partnership Securities are held by any Group Member, such Partnership Securities shall not be considered Outstanding for any purpose, except as otherwise provided herein. The General Partner or any Affiliate of the General Partner may also purchase or otherwise acquire and sell or otherwise dispose of Partnership Securities for its own account, subject to the provisions of Articles IV and X.

Section 7.12 Registration Rights of the General Partner and its Affiliates.

(a) If (i) the General Partner or any Affiliate of the General Partner (including for purposes of this Section 7.12, any Person that is an Affiliate of the General Partner at the date hereof notwithstanding that it may later cease to be an Affiliate of the General Partner) holds Partnership Securities that it desires to sell and (ii) Rule 144 of the Securities Act (or any successor rule or regulation to Rule 144) or another exemption from registration is not available to enable such holder of Partnership Securities (the “Holder”) to dispose of the number of Partnership Securities it desires to sell at the time it desires to do so without registration under the Securities Act, then at the option and upon the request of the Holder, the Partnership shall file with the Commission as promptly as practicable after receiving such request, and use all commercially reasonable efforts to cause to become effective and remain effective for a period of not less than six months following its effective

 

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date or such shorter period as shall terminate when all Partnership Securities covered by such registration statement have been sold, a registration statement under the Securities Act registering the offering and sale of the number of Partnership Securities specified by the Holder; provided, however, that the Partnership shall not be required to effect more than three registrations pursuant to this Section 7.12(a); and provided further, however, that if the Conflicts Committee determines that a postponement of the requested registration would be in the best interests of the Partnership and its Partners due to a pending transaction, investigation or other event, the filing of such registration statement or the effectiveness thereof may be deferred for up to six months, but not thereafter. In connection with any registration pursuant to the immediately preceding sentence, the Partnership shall (i) promptly prepare and file (A) such documents as may be necessary to register or qualify the securities subject to such registration under the securities laws of such states as the Holder shall reasonably request; provided, however, that no such qualification shall be required in any jurisdiction where, as a result thereof, the Partnership would become subject to general service of process or to taxation or qualification to do business as a foreign corporation or partnership doing business in such jurisdiction solely as a result of such registration, and (B) such documents as may be necessary to apply for listing or to list the Partnership Securities subject to such registration on such National Securities Exchange as the Holder shall reasonably request, and (ii) do any and all other acts and things that may be necessary or appropriate to enable the Holder to consummate a public sale of such Partnership Securities in such states. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(b) If the Partnership shall at any time propose to file a registration statement under the Securities Act for an offering of Partnership Securities for cash (other than an offering relating solely to a benefit plan), the Partnership shall use all commercially reasonable efforts to include such number or amount of Partnership Securities held by any Holder in such registration statement as the Holder shall request; provided, that the Partnership is not required to make any effort or take any action to so include the Partnership Securities of the Holder once the registration statement becomes or is declared effective by the Commission, including any registration statement providing for the offering from time to time of Partnership Securities pursuant to Rule 415 of the Securities Act. If the proposed offering pursuant to this Section 7.12(b) shall be an underwritten offering, then, in the event that the managing underwriter or managing underwriters of such offering advise the Partnership and the Holder in writing that in their opinion the inclusion of all or some of the Holder’s Partnership Securities would adversely and materially affect the timing or success of the offering, the Partnership shall include in such offering only that number or amount, if any, of Partnership Securities held by the Holder that, in the opinion of the managing underwriter or managing underwriters, will not so adversely and materially affect the offering. Except as set forth in Section 7.12(c), all costs and expenses of any such registration and offering (other than the underwriting discounts and commissions) shall be paid by the Partnership, without reimbursement by the Holder.

(c) If underwriters are engaged in connection with any registration referred to in this Section 7.12, the Partnership shall provide indemnification, representations, covenants, opinions and other assurance to the underwriters in form and substance reasonably satisfactory to such underwriters. Further, in addition to and not in limitation of the Partnership’s obligation under Section 7.7, the Partnership shall, to the fullest extent permitted by law, indemnify and hold harmless the Holder, its officers, directors and each Person who controls the Holder (within the meaning of the Securities Act) and any agent thereof (collectively, “Indemnified Persons”) from and against any and all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which any Indemnified Person may be involved, or is threatened to be involved, as a party or otherwise, under the Securities Act or otherwise (hereinafter referred to in this Section 7.12(c) as a “claim” and in the plural as “claims”) based upon, arising out of or resulting from any untrue statement or alleged untrue statement of any material fact contained in any registration statement under which any Partnership Securities were registered under the

 

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Securities Act or any state securities or Blue Sky laws, in any preliminary prospectus (if used prior to the effective date of such registration statement), or in any summary or final prospectus or free writing prospectus or in any amendment or supplement thereto (if used during the period the Partnership is required to keep the registration statement current), or arising out of, based upon or resulting from the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements made therein not misleading; provided, however, that the Partnership shall not be liable to any Indemnified Person to the extent that any such claim arises out of, is based upon or results from an untrue statement or alleged untrue statement or omission or alleged omission made in such registration statement, such preliminary, summary or final prospectus or free writing prospectus or such amendment or supplement, in reliance upon and in conformity with written information furnished to the Partnership by or on behalf of such Indemnified Person specifically for use in the preparation thereof.

(d) The provisions of Section 7.12(a) and Section 7.12(b) shall continue to be applicable with respect to the General Partner (and any of the General Partner’s Affiliates) after it ceases to be a general partner of the Partnership, during a period of two years subsequent to the effective date of such cessation and for so long thereafter as is required for the Holder to sell all of the Partnership Securities with respect to which it has requested during such two-year period inclusion in a registration statement otherwise filed or that a registration statement be filed; provided, however, that the Partnership shall not be required to file successive registration statements covering the same Partnership Securities for which registration was demanded during such two-year period. The provisions of Section 7.12(c) shall continue in effect thereafter.

(e) The rights to cause the Partnership to register Partnership Securities pursuant to this Section 7.12 may be assigned (but only with all related obligations) by a Holder to a transferee or assignee of such Partnership Securities, provided (i) the Partnership is, within a reasonable time after such transfer, furnished with written notice of the name and address of such transferee or assignee and the Partnership Securities with respect to which such registration rights are being assigned; and (ii) such transferee or assignee agrees in writing to be bound by and subject to the terms set forth in this Section 7.12.

(f) Any request to register Partnership Securities pursuant to this Section 7.12 shall (i) specify the Partnership Securities intended to be offered and sold by the Person making the request, (ii) express such Person’s present intent to offer such Partnership Securities for distribution, (iii) describe the nature or method of the proposed offer and sale of Partnership Securities, and (iv) contain the undertaking of such Person to provide all such information and materials and take all action as may be required in order to permit the Partnership to comply with all applicable requirements in connection with the registration of such Partnership Securities.

Section 7.13 Reliance by Third Parties.

Notwithstanding anything to the contrary in this Agreement, any Person dealing with the Partnership shall be entitled to assume that the General Partner and any officer of the General Partner authorized by the General Partner to act on behalf of and in the name of the Partnership has full power and authority to encumber, sell or otherwise use in any manner any and all assets of the Partnership and to enter into any authorized contracts on behalf of the Partnership, and such Person shall be entitled to deal with the General Partner or any such officer as if it were the Partnership’s sole party in interest, both legally and beneficially. Each Limited Partner hereby waives, to the fullest extent permitted by law, any and all defenses or other remedies that may be available against such Person to contest, negate or disaffirm any action of the General Partner or any such officer in connection with any such dealing. In no event shall any Person dealing with the General Partner or any such officer or its representatives be obligated to ascertain that the terms of this Agreement have been complied with or to inquire into the necessity or expedience of any act or action of the General Partner or any such officer or its representatives. Each and every certificate, document or other instrument executed on behalf of the Partnership by the General Partner or its representatives shall be conclusive evidence in favor of any and every Person

 

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relying thereon or claiming thereunder that (a) at the time of the execution and delivery of such certificate, document or instrument, this Agreement was in full force and effect, (b) the Person executing and delivering such certificate, document or instrument was duly authorized and empowered to do so for and on behalf of the Partnership and (c) such certificate, document or instrument was duly executed and delivered in accordance with the terms and provisions of this Agreement and is binding upon the Partnership.

ARTICLE VIII

BOOKS, RECORDS, ACCOUNTING AND REPORTS

Section 8.1 Records and Accounting.

The General Partner shall keep or cause to be kept at the principal office of the Partnership appropriate books and records with respect to the Partnership’s business, including all books and records necessary to provide to the Limited Partners any information required to be provided pursuant to Section 3.4(a). Any books and records maintained by or on behalf of the Partnership in the regular course of its business, including the record of the Record Holders of Units or other Partnership Securities, books of account and records of Partnership proceedings, may be kept on, or be in the form of, computer disks, hard drives, magnetic tape, photographs, micrographics or any other information storage device; provided, that the books and records so maintained are convertible into clearly legible written form within a reasonable period of time. The books of the Partnership shall be maintained, for financial reporting purposes, on an accrual basis in accordance with U.S. GAAP. The Partnership shall not be required to keep books maintained on a cash basis and the General Partner shall be permitted to calculate cash-based measures, including Operating Surplus and Adjusted Operating Surplus, by making such adjustments to its accrual basis books to account for non-cash items and other adjustments as the General Partner determines to be necessary or appropriate.

Section 8.2 Fiscal Year.

The fiscal year of the Partnership shall be a fiscal year ending December 31.

Section 8.3 Reports.

(a) As soon as practicable, but in no event later than 90 days after the close of each fiscal year of the Partnership, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit as of a date selected by the General Partner, an annual report containing financial statements of the Partnership for such fiscal year of the Partnership, presented in accordance with U.S. GAAP, including a balance sheet and statements of operations, Partnership equity and cash flows, such statements to be audited by a firm of independent public accountants selected by the General Partner.

(b) As soon as practicable, but in no event later than 45 days after the close of each Quarter except the last Quarter of each fiscal year, the General Partner shall cause to be mailed or made available, by any reasonable means to each Record Holder of a Unit, as of a date selected by the General Partner, a report containing unaudited financial statements of the Partnership and such other information as may be required by applicable law, regulation or rule of any National Securities Exchange on which the Units are listed or admitted to trading, or as the General Partner determines to be necessary or appropriate.

(c) The General Partner shall be deemed to have made a report available to each Record Holder as required by this Section 8.3 if it has either (i) filed such report with the Commission via its Electronic Data Gathering, Analysis and Retrieval system and such report is publicly available on such system or (ii) made such report available on any publicly available website maintained by the Partnership.

 

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ARTICLE IX

TAX MATTERS

Section 9.1 Tax Returns and Information.

The Partnership shall timely file all returns of the Partnership that are required for federal, state and local income tax purposes on the basis of the accrual method and the taxable period or years that it is required by law to adopt, from time to time, as determined by the General Partner. In the event the Partnership is required to use a taxable period other than a year ending on December 31, the General Partner shall use reasonable efforts to change the taxable period of the Partnership to a year ending on December 31. The tax information reasonably required by Record Holders for federal and state income tax reporting purposes with respect to a taxable period shall be furnished to them within 90 days of the close of the calendar year in which the Partnership’s taxable period ends. The classification, realization and recognition of income, gain, losses and deductions and other items shall be on the accrual method of accounting for federal income tax purposes.

Section 9.2 Tax Elections.

(a) The Partnership shall make the election under Section 754 of the Code in accordance with applicable regulations thereunder, subject to the reservation of the right to seek to revoke any such election upon the General Partner’s determination that such revocation is in the best interests of the Limited Partners. Notwithstanding any other provision herein contained, for the purposes of computing the adjustments under Section 743(b) of the Code, the General Partner shall be authorized (but not required) to adopt a convention whereby the price paid by a transferee of a Limited Partner Interest will be deemed to be the lowest quoted closing price of the Limited Partner Interests on any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading during the calendar month in which such transfer is deemed to occur pursuant to Section 6.2(g) without regard to the actual price paid by such transferee.

(b) Except as otherwise provided herein, the General Partner shall determine whether the Partnership should make any other elections permitted by the Code.

Section 9.3 Tax Controversies.

Subject to the provisions hereof, the General Partner is designated as the Tax Matters Partner (as defined in the Code) and is authorized and required to represent the Partnership (at the Partnership’s expense) in connection with all examinations of the Partnership’s affairs by tax authorities, including resulting administrative and judicial proceedings, and to expend Partnership funds for professional services and costs associated therewith. Each Partner agrees to cooperate with the General Partner and to do or refrain from doing any or all things reasonably required by the General Partner to conduct such proceedings.

Section 9.4 Withholding.

Notwithstanding any other provision of this Agreement, the General Partner is authorized to take any action that may be required to cause the Partnership and other Group Members to comply with any withholding requirements established under the Code or any other federal, state or local law including pursuant to Sections 1441, 1442, 1445 and 1446 of the Code. To the extent that the Partnership is required or elects to withhold and pay over to any taxing authority any amount resulting from the allocation or distribution of income to any Partner (including by reason of Section 1446 of the Code), the General Partner may treat the amount withheld as a distribution of cash pursuant to Section 6.3(c) in the amount of such withholding from such Partner.

 

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ARTICLE X

ADMISSION OF PARTNERS

Section 10.1 Admission of Limited Partners.

(a) Upon the issuance by the Partnership of Common Units, Subordinated Units and Incentive Distribution Rights to the General Partner, Chesapeake Holdings, each of the GIP Entities and the Underwriters as described in Article V in connection with the Initial Offering, such parties shall be automatically admitted to the Partnership as Initial Limited Partners in respect of the Common Units, Subordinated Units or Incentive Distribution Rights issued to them.

(b) By acceptance of the transfer of any Limited Partner Interests in accordance with Article IV or the acceptance of any Limited Partner Interests issued pursuant to Article V or pursuant to a merger or consolidation or conversion pursuant to Article XIV, and except as provided in Section 4.9, each transferee of, or other such Person acquiring, a Limited Partner Interest (including any nominee holder or an agent or representative acquiring such Limited Partner Interests for the account of another Person) (i) shall be admitted to the Partnership as a Limited Partner with respect to the Limited Partner Interests so transferred or issued to such Person when any such transfer or admission is reflected in the books and records of the Partnership and such Limited Partner becomes the Record Holder of the Limited Partner Interests so transferred, (ii) shall become bound, and shall be deemed to have agreed to be bound, by the terms of this Agreement, (iii) represents that the transferee or other recipient has the capacity, power and authority to enter into this Agreement and (iv) makes the consents, acknowledgements and waivers contained in this Agreement, all with or without execution of this Agreement by such Person. The transfer of any Limited Partner Interests and the admission of any new Limited Partner shall not constitute an amendment to this Agreement. A Person may become a Limited Partner or Record Holder of a Limited Partner Interest without the consent or approval of any of the Partners. A Person may not become a Limited Partner without acquiring a Limited Partner Interest and until such Person is reflected in the books and records of the Partnership as the Record Holder of such Limited Partner Interest. The rights and obligations of a Person who is an Ineligible Holder shall be determined in accordance with Section 4.9.

(c) The name and mailing address of each Limited Partner shall be listed on the books and records of the Partnership maintained for such purpose by the Partnership or the Transfer Agent. The General Partner shall update the books and records of the Partnership from time to time as necessary to reflect accurately the information therein (or shall cause the Transfer Agent to do so, as applicable). A Limited Partner Interest may be represented by a Certificate, as provided in Section 4.1.

(d) Any transfer of a Limited Partner Interest shall not entitle the transferee to share in the profits and losses, to receive distributions, to receive allocations of income, gain, loss, deduction or credit or any similar item or to any other rights to which the transferor was entitled until the transferee becomes a Limited Partner pursuant to Section 10.1(b).

Section 10.2 Admission of Successor General Partner.

A successor General Partner approved pursuant to Section 11.1 or Section 11.2 or the transferee of or successor to all of the General Partner Interest pursuant to Section 4.6 who is proposed to be admitted as a successor General Partner shall be admitted to the Partnership as the General Partner, effective immediately prior to the withdrawal or removal of the predecessor or transferring General Partner, pursuant to Section 11.1 or 11.2 or the transfer of the General Partner Interest pursuant to Section 4.6, provided, however, that no such successor shall be admitted to the Partnership until compliance with the terms of Section 4.6 has occurred and such successor has executed and delivered such other documents or instruments as may be required to effect such admission. Any such successor shall, subject to the terms hereof, carry on the business of the members of the Partnership Group without dissolution.

 

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Section 10.3 Amendment of Agreement and Certificate of Limited Partnership.

To effect the admission to the Partnership of any Partner, the General Partner shall take all steps necessary or appropriate under the Delaware Act to amend the records of the Partnership to reflect such admission and, if necessary, to prepare as soon as practicable an amendment to this Agreement and, if required by law, the General Partner shall prepare and file an amendment to the Certificate of Limited Partnership.

ARTICLE XI

WITHDRAWAL OR REMOVAL OF PARTNERS

Section 11.1 Withdrawal of the General Partner.

(a) The General Partner shall be deemed to have withdrawn from the Partnership upon the occurrence of any one of the following events (each such event herein referred to as an “Event of Withdrawal”);

(i) The General Partner voluntarily withdraws from the Partnership by giving written notice to the other Partners;

(ii) The General Partner transfers all of its General Partner Interest pursuant to Section 4.6;

(iii) The General Partner is removed pursuant to Section 11.2;

(iv) The General Partner (A) makes a general assignment for the benefit of creditors; (B) files a voluntary bankruptcy petition for relief under Chapter 7 of the United States Bankruptcy Code; (C) files a petition or answer seeking for itself a liquidation, dissolution or similar relief (but not a reorganization) under any law; (D) files an answer or other pleading admitting or failing to contest the material allegations of a petition filed against the General Partner in a proceeding of the type described in clauses (A)-(C) of this Section 11.1(a)(iv); or (E) seeks, consents to or acquiesces in the appointment of a trustee (but not a debtor-in-possession), receiver or liquidator of the General Partner or of all or any substantial part of its properties;

(v) A final and non-appealable order of relief under Chapter 7 of the United States Bankruptcy Code is entered by a court with appropriate jurisdiction pursuant to a voluntary or involuntary petition by or against the General Partner; or

(vi) (A) in the event the General Partner is a corporation, a certificate of dissolution or its equivalent is filed for the General Partner, or 90 days expire after the date of notice to the General Partner of revocation of its charter without a reinstatement of its charter, under the laws of its state of incorporation; (B) in the event the General Partner is a partnership or a limited liability company, the dissolution and commencement of winding up of the General Partner; (C) in the event the General Partner is acting in such capacity by virtue of being a trustee of a trust, the termination of the trust; (D) in the event the General Partner is a natural person, his death or adjudication of incompetency; and (E) otherwise in the event of the termination of the General Partner.

If an Event of Withdrawal specified in Section 11.1(a)(iv), (v) or (vi)(A), (B), (C) or (E) occurs, the withdrawing General Partner shall give notice to the Limited Partners within 30 days after such occurrence. The Partners hereby agree that only the Events of Withdrawal described in this Section 11.1 shall result in the withdrawal of the General Partner from the Partnership.

(b) Withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall not constitute a breach of this Agreement under the following circumstances: (i) at any time during the period beginning on the Closing Date and ending at 11:59 pm, prevailing Central Time, on June 30, 2020, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to

 

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the Limited Partners; provided, that prior to the effective date of such withdrawal, the withdrawal is approved by Unitholders holding at least a majority of the Outstanding Common Units (excluding Common Units held by the General Partner and its Affiliates) and the General Partner delivers to the Partnership an Opinion of Counsel (“Withdrawal Opinion of Counsel”) that such withdrawal (following the selection of the successor General Partner) would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); (ii) at any time after 11:59 pm, prevailing Central Time, on June 30, 2020, the General Partner voluntarily withdraws by giving at least 90 days’ advance notice to the Unitholders, such withdrawal to take effect on the date specified in such notice; (iii) at any time that the General Partner ceases to be the General Partner pursuant to Section 11.1(a)(ii) or is removed pursuant to Section 11.2; or (iv) notwithstanding clause (i) of this sentence, at any time that the General Partner voluntarily withdraws by giving at least 90 days’ advance notice of its intention to withdraw to the Limited Partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one Person and its Affiliates (other than the General Partner and its Affiliates) own beneficially or of record or control at least 50% of the Outstanding Units. The withdrawal of the General Partner from the Partnership upon the occurrence of an Event of Withdrawal shall also constitute the withdrawal of the General Partner as general partner or managing member, if any, to the extent applicable, of the other Group Members. If the General Partner gives a notice of withdrawal pursuant to Section 11.1(a)(i), the holders of a Unit Majority, may, prior to the effective date of such withdrawal, elect a successor General Partner. The Person so elected as successor General Partner shall automatically become the successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If, prior to the effective date of the General Partner’s withdrawal pursuant to Section 11.1(a)(i), a successor is not selected by the Unitholders as provided herein or the Partnership does not receive a Withdrawal Opinion of Counsel, the Partnership shall be dissolved in accordance with Section 12.1 unless the business of the Partnership is continued pursuant to Section 12.2. Any successor General Partner elected in accordance with the terms of this Section 11.1 shall be subject to the provisions of Section 10.2.

Section 11.2 Removal of the General Partner.

The General Partner may be removed if such removal is approved by the Unitholders holding at least 66 2/3% of the Outstanding Units (including Units held by the General Partner and its Affiliates) voting as a single class. Any such action by such holders for removal of the General Partner must also provide for the election of a successor General Partner by the Unitholders holding a majority of the outstanding Common Units, voting as a single class and a majority of the outstanding Subordinated Units (if any Subordinated Units are then Outstanding) voting as a class (including, in each case, Units held by the General Partner and its Affiliates). Such removal shall be effective immediately following the admission of a successor General Partner pursuant to Section 10.2. The removal of the General Partner shall also automatically constitute the removal of the General Partner as general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. If a Person is elected as a successor General Partner in accordance with the terms of this Section 11.2, such Person shall, upon admission pursuant to Section 10.2, automatically become a successor general partner or managing member, to the extent applicable, of the other Group Members of which the General Partner is a general partner or a managing member. The right of the holders of Outstanding Units to remove the General Partner shall not exist or be exercised unless the Partnership has received an opinion opining as to the matters covered by a Withdrawal Opinion of Counsel. Any successor General Partner elected in accordance with the terms of this Section 11.2 shall be subject to the provisions of Section 10.2.

Section 11.3 Interest of Departing General Partner and Successor General Partner.

(a) In the event of (i) withdrawal of the General Partner under circumstances where such withdrawal does not violate this Agreement or (ii) removal of the General Partner by the holders of Outstanding Units under

 

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circumstances where Cause does not exist, if the successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2, the Departing General Partner shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner, to require its successor to purchase its General Partner Interest and its or its Affiliates’ or beneficial owners’ general partner interest (or equivalent interest), if any, in the other Group Members and all of its or its Affiliates’ Incentive Distribution Rights (collectively, the “Combined Interest”) in exchange for an amount in cash equal to the fair market value of such Combined Interest, such amount to be determined and payable as of the effective date of its withdrawal or removal. If the General Partner is removed by the Unitholders under circumstances where Cause exists or if the General Partner withdraws under circumstances where such withdrawal violates this Agreement, and if a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not the former General Partner), such successor shall have the option, exercisable prior to the effective date of the withdrawal or removal of such Departing General Partner (or, in the event the business of the Partnership is continued, prior to the date the business of the Partnership is continued), to purchase the Combined Interest for such fair market value of such Combined Interest. In either event, the Departing General Partner shall be entitled to receive all reimbursements due such Departing General Partner pursuant to Section 7.4, including any employee-related liabilities (including severance liabilities), incurred in connection with the termination of any employees employed by the Departing General Partner or its Affiliates (other than any Group Member) for the benefit of the Partnership or the other Group Members.

For purposes of this Section 11.3(a), the fair market value of the Combined Interest shall be determined by agreement between the Departing General Partner and its successor or, failing agreement within 30 days after the effective date of such Departing General Partner’s withdrawal or removal, by an independent investment banking firm or other independent expert selected by the Departing General Partner and its successor, which, in turn, may rely on other experts, and the determination of which shall be conclusive as to such matter. If such parties cannot agree upon one independent investment banking firm or other independent expert within 45 days after the effective date of such withdrawal or removal, then the Departing General Partner shall designate an independent investment banking firm or other independent expert, the Departing General Partner’s successor shall designate an independent investment banking firm or other independent expert, and such firms or experts shall mutually select a third independent investment banking firm or independent expert, which third independent investment banking firm or other independent expert shall determine the fair market value of the Combined Interest. In making its determination, such third independent investment banking firm or other independent expert shall consider the value of the Units, including the then current trading price of Units on any National Securities Exchange on which Units are then listed or admitted to trading, the value of the Partnership’s assets, the rights and obligations of the Departing General Partner (including an appropriate “control premium”), the value of the Incentive Distribution Rights and the General Partner Units and other factors it may deem relevant.

(b) If the Combined Interest is not purchased in the manner set forth in Section 11.3(a), the Departing General Partner (or its transferee) shall become a Limited Partner and the Combined Interest shall be converted into Common Units pursuant to a valuation made by an investment banking firm or other independent expert selected pursuant to Section 11.3(a), without reduction in such Partnership Interest (but subject to proportionate dilution by reason of the admission of its successor). Any successor General Partner shall indemnify the Departing General Partner (or its transferee) as to all debts and liabilities of the Partnership arising on or after the date on which the Departing General Partner (or its transferee) becomes a Limited Partner. For purposes of this Agreement, conversion of the Combined Interest to Common Units will be characterized as if the Departing General Partner (or its transferee) contributed the Combined Interest to the Partnership in exchange for the newly issued Common Units.

(c) If a successor General Partner is elected in accordance with the terms of Section 11.1 or Section 11.2 (or if the business of the Partnership is continued pursuant to Section 12.2 and the successor General Partner is not

 

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the former General Partner) and the option described in Section 11.3(a) is not exercised by the party entitled to do so, the successor General Partner shall, at the effective date of its admission to the Partnership, contribute to the Partnership cash in the amount equal to the product of (x) the quotient obtained by dividing (A) the Percentage Interest of the General Partner Interest of the Departing General Partner by (B) a percentage equal to 100% less the Percentage Interest of the General Partner Interest of the Departing General Partner and (y) the Net Agreed Value of the Partnership’s assets on such date. In such event, such successor General Partner shall, subject to the following sentence, be entitled to its Percentage Interest of all Partnership allocations and distributions to which the Departing General Partner was entitled. In addition, the successor General Partner shall cause this Agreement to be amended to reflect that, from and after the date of such successor General Partner’s admission, the successor General Partner’s interest in all Partnership distributions and allocations shall be its Percentage Interest.

Section 11.4 Termination of Subordination Period, Conversion of Subordinated Units and Extinguishment of Cumulative Common Unit Arrearages.

Notwithstanding any provision of this Agreement, if the General Partner is removed as general partner of the Partnership under circumstances where Cause does not exist:

(a) the Subordinated Units held by any Person will immediately and automatically convert into Common Units on a one-for-one basis, provided (i) neither such Person nor any of its Affiliates voted any of its Units in favor of the removal and (ii) such Person is not an Affiliate of the successor General Partner; and

(b) if all of the Subordinated Units convert into Common Units pursuant to Section 11.4(a), all Cumulative Common Unit Arrearages on the Common Units will be extinguished and the Subordination Period will end;

provided, however, that such converted Subordinated Units shall remain subject to the provisions of Sections 5.5(c)(ii), 6.1(d)(x) and 6.7.

Section 11.5 Withdrawal of Limited Partners.

No Limited Partner shall have any right to withdraw from the Partnership; provided, however, that when a transferee of a Limited Partner’s Limited Partner Interest becomes a Record Holder of the Limited Partner Interest so transferred, such transferring Limited Partner shall cease to be a Limited Partner with respect to the Limited Partner Interest so transferred.

ARTICLE XII

DISSOLUTION AND LIQUIDATION

Section 12.1 Dissolution.

The Partnership shall not be dissolved by the admission of additional Limited Partners or by the admission of a successor General Partner in accordance with the terms of this Agreement. Upon the removal or withdrawal of the General Partner, if a successor General Partner is elected pursuant to Section 11.1, 11.2 or 12.2, the Partnership shall not be dissolved and such successor General Partner is hereby authorized to, and shall, continue the business of the Partnership. Subject to Section 12.2, the Partnership shall dissolve, and its affairs shall be wound up, upon:

(a) an Event of Withdrawal of the General Partner as provided in Section 11.1(a) (other than Section 11.1(a)(ii)), unless a successor is elected and such successor is admitted to the Partnership pursuant to this Agreement;

 

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(b) an election to dissolve the Partnership by the General Partner that is approved by the holders of a Unit Majority;

(c) the entry of a decree of judicial dissolution of the Partnership pursuant to the provisions of the Delaware Act; or

(d) at any time there are no Limited Partners, unless the Partnership is continued without dissolution in accordance with the Delaware Act.

Section 12.2 Continuation of the Business of the Partnership After Dissolution.

Upon (a) an Event of Withdrawal caused by the withdrawal or removal of the General Partner as provided in Section 11.1(a)(i) or (iii) and the failure of the Partners to select a successor to such Departing General Partner pursuant to Section 11.1 or Section 11.2, then within 90 days thereafter, or (b) an event constituting an Event of Withdrawal as defined in Section 11.1(a)(iv), (v) or (vi), then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a Unit Majority may elect to continue the business of the Partnership on the same terms and conditions set forth in this Agreement by appointing as a successor General Partner a Person approved by the holders of a Unit Majority. Unless such an election is made within the applicable time period as set forth above, the Partnership shall conduct only activities necessary to wind up its affairs. If such an election is so made, then:

(i) the Partnership shall continue without dissolution unless earlier dissolved in accordance with this Article XII;

(ii) if the successor General Partner is not the former General Partner, then the interest of the former General Partner shall be treated in the manner provided in Section 11.3; and

(iii) the successor General Partner shall be admitted to the Partnership as General Partner, effective as of the Event of Withdrawal, by agreeing in writing to be bound by this Agreement;

provided, that the right of the holders of a Unit Majority to approve a successor General Partner and to continue the business of the Partnership shall not exist and may not be exercised unless the Partnership has received an Opinion of Counsel that (x) the exercise of the right would not result in the loss of limited liability under the Delaware Act of any Limited Partner and (y) neither the Partnership nor any Group Member 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 such right to continue (to the extent not already so treated or taxed).

Section 12.3 Liquidator.

Upon dissolution of the Partnership, unless the business of the Partnership is continued pursuant to Section 12.2, the General Partner shall select one or more Persons to act as Liquidator. The Liquidator (if other than the General Partner) shall be entitled to receive such compensation for its services as may be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. The Liquidator (if other than the General Partner) shall agree not to resign at any time without 15 days’ prior notice and may be removed at any time, with or without cause, by notice of removal approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. Upon dissolution, removal or resignation of the Liquidator, a successor and substitute Liquidator (who shall have and succeed to all rights, powers and duties of the original Liquidator) shall within 30 days thereafter be approved by holders of at least a majority of the Outstanding Common Units and Subordinated Units, voting as a single class. The right to approve a successor or substitute Liquidator in the manner provided herein shall be deemed to refer also to any such successor or substitute Liquidator approved in the manner herein provided. Except as expressly

 

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provided in this Article XII, the Liquidator approved in the manner provided herein shall have and may exercise, without further authorization or consent of any of the parties hereto, all of the powers conferred upon the General Partner under the terms of this Agreement (but subject to all of the applicable limitations, contractual and otherwise, upon the exercise of such powers, other than the limitation on sale set forth in Section 7.3) necessary or appropriate to carry out the duties and functions of the Liquidator hereunder for and during the period of time required to complete the winding up and liquidation of the Partnership as provided for herein.

Section 12.4 Liquidation.

The Liquidator shall proceed to dispose of the assets of the Partnership, discharge its liabilities, and otherwise wind up its affairs in such manner and over such period as determined by the Liquidator, subject to Section 17-804 of the Delaware Act and the following:

(a) The assets may be disposed of by public or private sale or by distribution in kind to one or more Partners on such terms as the Liquidator and such Partner or Partners may agree. If any property is distributed in kind, the Partner receiving the property shall be deemed for purposes of Section 12.4(c) to have received cash equal to its fair market value; and contemporaneously therewith, appropriate cash distributions must be made to the other Partners. The Liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable time if it determines that an immediate sale or distribution of all or some of the Partnership’s assets would be impractical or would cause undue loss to the Partners. The Liquidator may distribute the Partnership’s assets, in whole or in part, in kind if it determines that a sale would be impractical or would cause undue loss to the Partners.

(b) Liabilities of the Partnership include amounts owed to the Liquidator as compensation for serving in such capacity (subject to the terms of Section 12.3) and amounts to Partners otherwise than in respect of their distribution rights under Article VI. With respect to any liability that is contingent, conditional or unmatured or is otherwise not yet due and payable, the Liquidator shall either settle such claim for such amount as it thinks appropriate or establish a reserve of cash or other assets to provide for its payment. When paid, any unused portion of the reserve shall be distributed as additional liquidation proceeds.

(c) All property and all cash in excess of that required to discharge liabilities as provided in Section 12.4(b) shall be distributed to the Partners in accordance with, and to the extent of, the positive balances in their respective Capital Accounts, as determined after taking into account all Capital Account adjustments (other than those made by reason of distributions pursuant to this Section 12.4(c)) for the taxable period of the Partnership during which the liquidation of the Partnership occurs (with such date of occurrence being determined pursuant to Treasury Regulation Section 1.704-1(b)(2)(ii)(g)), and such distribution shall be made by the end of such taxable period (or, if later, within 90 days after said date of such occurrence).

Section 12.5 Cancellation of Certificate of Limited Partnership.

Upon the completion of the distribution of Partnership cash and property as provided in Section 12.4 in connection with the liquidation of the Partnership, the Certificate of Limited Partnership and all qualifications of the Partnership as a foreign limited partnership in jurisdictions other than the State of Delaware shall be canceled and such other actions as may be necessary to terminate the Partnership shall be taken.

Section 12.6 Return of Contributions.

The General Partner shall not be personally liable for, and shall have no obligation to contribute or loan any monies or property to the Partnership to enable it to effectuate, the return of the Capital Contributions of the Limited Partners or Unitholders, or any portion thereof, it being expressly understood that any such return shall be made solely from Partnership assets.

 

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Section 12.7 Waiver of Partition.

To the maximum extent permitted by law, each Partner hereby waives any right to partition of the Partnership property.

Section 12.8 Capital Account Restoration.

No Limited Partner shall have any obligation to restore any negative balance in its Capital Account upon liquidation of the Partnership. The General Partner shall be obligated to restore any negative balance in its Capital Account upon liquidation of its interest in the Partnership by the end of the taxable period of the Partnership during which such liquidation occurs, or, if later, within 90 days after the date of such liquidation.

ARTICLE XIII

AMENDMENT OF PARTNERSHIP AGREEMENT; MEETINGS; RECORD DATE

Section 13.1 Amendments to be Adopted Solely by the General Partner.

Each Partner agrees that the General Partner, without the approval of any Partner, may amend any provision of this Agreement and execute, swear to, acknowledge, deliver, file and record whatever documents may be required in connection therewith, to reflect:

(a) a change in the name of the Partnership, the location of the principal place of business of the Partnership, the registered agent of the Partnership or the registered office of the Partnership;

(b) admission, substitution, withdrawal or removal of Partners in accordance with this Agreement;

(c) a change that the General Partner determines to be necessary or appropriate to qualify or continue the qualification of the Partnership 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 the Group Members will not be treated as associations taxable as corporations or otherwise taxed as entities for federal income tax purposes;

(d) a change that the General Partner determines (i) does not adversely affect the Limited Partners (including any particular class of Partnership Interests as compared to other classes of Partnership Interests) in any material respect, (ii) to be necessary or appropriate to (A) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute (including the Delaware Act) or (B) facilitate the trading of the Units (including the division of any class or classes of Outstanding Units into different classes to facilitate uniformity of tax consequences within such classes of Units) or comply with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are or will be listed or admitted to trading, (iii) to be necessary or appropriate in connection with action taken by the General Partner pursuant to Section 5.9 or (iv) is required to effect the intent expressed in the Registration Statement or the intent of the provisions of this Agreement or is otherwise contemplated by this Agreement;

(e) a change in the fiscal year or taxable period of the Partnership and any other changes that the General Partner determines to be necessary or appropriate as a result of a change in the fiscal year or taxable period of the Partnership including, if the General Partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by the Partnership;

(f) an amendment that is necessary, in the Opinion of Counsel, to prevent the Partnership, or the General Partner or its directors, officers, trustees or agents from in any manner being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisers Act of 1940, as amended, or “plan

 

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asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended, regardless of whether such are substantially similar to plan asset regulations currently applied or proposed by the United States Department of Labor;

(g) an amendment that the General Partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of any class or series of Partnership Securities and options, rights, warrants and appreciation rights relating to the Partnership Securities pursuant to Section 5.6;

(h) any amendment expressly permitted in this Agreement to be made by the General Partner acting alone;

(i) an amendment effected, necessitated or contemplated by a Merger Agreement approved in accordance with Section 14.3;

(j) an amendment that the General Partner determines to be necessary or appropriate to reflect and account for the formation by the Partnership of, or investment by the Partnership in, any corporation, partnership, joint venture, limited liability company or other entity, in connection with the conduct by the Partnership of activities permitted by the terms of Section 2.4 or 7.1(a);

(k) a merger, conveyance or conversion pursuant to Section 14.3(d); or

(l) any other amendments substantially similar to the foregoing.

Section 13.2 Amendment Procedures.

Except as provided in Section 13.1 and Section 13.3, all amendments to this Agreement shall be made in accordance with the requirements contained in this Section 13.2. Amendments to this Agreement may be proposed only by the General Partner; provided, however, that to the fullest extent permitted by law, the General Partner shall have no duty or obligation to propose any amendment to this Agreement and may decline to do so free of any duty (including any fiduciary duty) or obligation whatsoever to the Partnership, any Limited Partner or any other Person bound by this Agreement, and, in declining to propose an amendment, to the fullest extent permitted by law shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any Group Member Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity. A proposed amendment shall be effective upon its approval by the General Partner and the holders of a Unit Majority, unless a greater or different percentage is required under this Agreement or by Delaware law. Each proposed amendment that requires the approval of the holders of a specified percentage of Outstanding Units shall be set forth in a writing that contains the text of the proposed amendment. If such an amendment is proposed, the General Partner shall seek the written approval of the requisite percentage of Outstanding Units or call a meeting of the Unitholders to consider and vote on such proposed amendment, in each case in accordance with the other provisions of this Article XIII. The General Partner shall notify all Record Holders upon final adoption of any such proposed amendments.

Section 13.3 Amendment Requirements.

(a) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no provision of this Agreement that establishes a percentage of Outstanding Units required to take any action shall be amended, altered, changed, repealed or rescinded in any respect that would have the effect of reducing such voting percentage unless such amendment is approved by the written consent or the affirmative vote of holders of Outstanding Units whose aggregate Outstanding Units constitute not less than the voting requirement sought to be reduced.

 

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(b) Notwithstanding the provisions of Section 13.1 (other than Section 13.1(d)(iv)) and Section 13.2, no amendment to this Agreement may (i) enlarge the obligations of (including requiring any holder of a class of Partnership Interests to make additional Capital Contributions to the Partnership) any Limited Partner without its consent, unless such shall be deemed to have occurred as a result of an amendment approved pursuant to Section 13.3(c), or (ii) enlarge the obligations of, restrict, change or modify in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, the General Partner or any of its Affiliates without its consent, which consent may be given or withheld at its option.

(c) Except as provided in Section 14.3, and without limitation of the General Partner’s authority to adopt amendments to this Agreement without the approval of any Partners as contemplated in Section 13.1, any amendment that would have a material adverse effect on the rights or preferences of any class of Partnership Interests in relation to other classes of Partnership Interests must be approved by the holders of not less than a majority of the Outstanding Partnership Interests of the class affected.

(d) Notwithstanding any other provision of this Agreement, except for amendments pursuant to Section 13.1 and except as otherwise provided by Section 14.3(b), no amendments shall become effective without the approval of the holders of at least 90% of the Outstanding Units voting as a single class unless the Partnership obtains an Opinion of Counsel to the effect that such amendment will not affect the limited liability of any Limited Partner under applicable partnership law of the state under whose laws the Partnership is organized.

(e) Except as provided in Section 13.1, this Section 13.3 shall only be amended with the approval of the holders of at least 90% of the Outstanding Units.

Section 13.4 Special Meetings.

All acts of Limited Partners to be taken pursuant to this Agreement shall be taken in the manner provided in this Article XIII. Special meetings of the Limited Partners may be called by the General Partner or by Limited Partners owning 20% or more of the Outstanding Units of the class or classes for which a meeting is proposed. Limited Partners shall call a special meeting by delivering to the General Partner one or more requests in writing stating that the signing Limited Partners wish to call a special meeting and indicating the general or specific purposes for which the special meeting is to be called. Within 60 days after receipt of such a call from Limited Partners or within such greater time as may be reasonably necessary for the Partnership to comply with any statutes, rules, regulations, listing agreements or similar requirements governing the holding of a meeting or the solicitation of proxies for use at such a meeting, the General Partner shall send a notice of the meeting to the Limited Partners either directly or indirectly through the Transfer Agent. A meeting shall be held at a time and place determined by the General Partner on a date not less than 10 days nor more than 60 days after the time notice of the meeting is given as provided in Section 16.1. Limited Partners shall not vote on matters that would cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability under the Delaware Act or the law of any other state in which the Partnership is qualified to do business.

Section 13.5 Notice of a Meeting.

Notice of a meeting called pursuant to Section 13.4 shall be given to the Record Holders of the class or classes of Units for which a meeting is proposed in writing by mail or other means of written communication in accordance with Section 16.1. The notice shall be deemed to have been given at the time when deposited in the mail or sent by other means of written communication.

 

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Section 13.6 Record Date.

For purposes of determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners or to give approvals without a meeting as provided in Section 13.11 the General Partner may set a Record Date, which shall not be less than 10 nor more than 60 days before (a) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading or U.S. federal securities laws, in which case the rule, regulation, guideline or requirement of such National Securities Exchange or U.S. federal securities laws shall govern) or (b) in the event that approvals are sought without a meeting, the date by which Limited Partners are requested in writing by the General Partner to give such approvals. If the General Partner does not set a Record Date, then (a) the Record Date for determining the Limited Partners entitled to notice of or to vote at a meeting of the Limited Partners shall be the close of business on the day next preceding the day on which notice is given, and (b) the Record Date for determining the Limited Partners entitled to give approvals without a meeting shall be the date the first written approval is deposited with the Partnership in care of the General Partner in accordance with Section 13.11.

Section 13.7 Adjournment.

When a meeting is adjourned to another time or place, notice need not be given of the adjourned meeting and a new Record Date need not be fixed, if the time and place thereof are announced at the meeting at which the adjournment is taken, unless such adjournment shall be for more than 45 days. At the adjourned meeting, the Partnership may transact any business which might have been transacted at the original meeting. If the adjournment is for more than 45 days or if a new Record Date is fixed for the adjourned meeting, a notice of the adjourned meeting shall be given in accordance with this Article XIII.

Section 13.8 Waiver of Notice; Approval of Meeting; Approval of Minutes.

The transactions of any meeting of Limited Partners, however called and noticed, and whenever held, shall be as valid as if it had occurred at a meeting duly held after regular call and notice, if a quorum is present either in person or by proxy. Attendance of a Limited Partner at a meeting shall constitute a waiver of notice of the meeting, except when the Limited Partner attends the meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened; and except that attendance at a meeting is not a waiver of any right to disapprove the consideration of matters required to be included in the notice of the meeting, but not so included, if the disapproval is expressly made at the meeting.

Section 13.9 Quorum and Voting.

The holders of a majority of the Outstanding Units of the class or classes for which a meeting has been called (including Outstanding Units owned by the General Partner) represented in person or by proxy shall constitute a quorum at a meeting of Limited Partners of such class or classes unless any such action by the Limited Partners requires approval by holders of a greater percentage of such Units, in which case the quorum shall be such greater percentage. At any meeting of the Limited Partners duly called and held in accordance with this Agreement at which a quorum is present, the act of Limited Partners holding Outstanding Units that in the aggregate represent a majority of the Outstanding Units entitled to vote and be present in person or by proxy at such meeting shall be deemed to constitute the act of all Limited Partners, unless a greater or different percentage is required with respect to such action under the provisions of this Agreement, in which case the act of the Limited Partners holding Outstanding Units that in the aggregate represent at least such greater or different percentage shall be required. The Limited Partners present at a duly called or held meeting at which a quorum is present may continue to transact business until adjournment, notwithstanding the withdrawal of enough Limited Partners to leave less than a quorum, if any action taken (other than adjournment) is approved by the required

 

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percentage of Outstanding Units specified in this Agreement. In the absence of a quorum any meeting of Limited Partners may be adjourned from time to time by the affirmative vote of holders of at least a majority of the Outstanding Units entitled to vote at such meeting represented either in person or by proxy, but no other business may be transacted, except as provided in Section 13.7.

Section 13.10 Conduct of a Meeting.

The General Partner shall have full power and authority concerning the manner of conducting any meeting of the Limited Partners or solicitation of approvals in writing, including the determination of Persons entitled to vote, the existence of a quorum, the satisfaction of the requirements of Section 13.4, the conduct of voting, the validity and effect of any proxies and the determination of any controversies, votes or challenges arising in connection with or during the meeting or voting. The General Partner shall designate a Person to serve as chairman of any meeting and shall further designate a Person to take the minutes of any meeting. All minutes shall be kept with the records of the Partnership maintained by the General Partner. The General Partner may make such other regulations consistent with applicable law and this Agreement as it may deem advisable concerning the conduct of any meeting of the Limited Partners or solicitation of approvals in writing, including regulations in regard to the appointment of proxies, the appointment and duties of inspectors of votes and approvals, the submission and examination of proxies and other evidence of the right to vote, and the revocation of approvals in writing.

Section 13.11 Action Without a Meeting.

If authorized by the General Partner, any action that may be taken at a meeting of the Limited Partners may be taken without a meeting, without a vote and without prior notice, if an approval in writing setting forth the action so taken is signed by Limited Partners owning not less than the minimum percentage of the Outstanding Units that would be necessary to authorize or take such action at a meeting at which all the Limited Partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any National Securities Exchange on which the Units are listed or admitted to trading, in which case the rule, regulation, guideline or requirement of such National Securities Exchange shall govern). Prompt notice of the taking of action without a meeting shall be given to the Limited Partners who have not approved in writing. The General Partner may specify that any written ballot, if any, submitted to Limited Partners for the purpose of taking any action without a meeting shall be returned to the Partnership within the time period, which shall be not less than 20 days, specified by the General Partner. If a ballot returned to the Partnership does not vote all of the Units held by the Limited Partners, the Partnership shall be deemed to have failed to receive a ballot for the Units that were not voted. If approval of the taking of any action by the Limited Partners is solicited by any Person other than by or on behalf of the General Partner, the written approvals shall have no force and effect unless and until (a) they are deposited with the Partnership in care of the General Partner and (b) an Opinion of Counsel is delivered to the General Partner to the effect that the exercise of such right and the action proposed to be taken with respect to any particular matter (i) will not cause the Limited Partners to be deemed to be taking part in the management and control of the business and affairs of the Partnership so as to jeopardize the Limited Partners’ limited liability, and (ii) is otherwise permissible under the state statutes then governing the rights, duties and liabilities of the Partnership and the Partners. Nothing contained in this Section 13.11 shall be deemed to require the General Partner to solicit all Limited Partners in connection with a matter approved by the holders of the requisite percentage of Units acting by written consent without a meeting.

Section 13.12 Right to Vote and Related Matters.

(a) Only those Record Holders of the Outstanding Units on the Record Date set pursuant to Section 13.6 (and also subject to the limitations contained in the definition of “Outstanding”) shall be entitled to notice of, and to vote at, a meeting of Limited Partners or to act with respect to matters as to which the holders of the

 

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Outstanding Units have the right to vote or to act. All references in this Agreement to votes of, or other acts that may be taken by, the Outstanding Units shall be deemed to be references to the votes or acts of the Record Holders of such Outstanding Units.

(b) With respect to Units that are held for a Person’s account by another Person (such as a broker, dealer, bank, trust company or clearing corporation, or an agent of any of the foregoing), in whose name such Units are registered, such other Person shall, in exercising the voting rights in respect of such Units on any matter, and unless the arrangement between such Persons provides otherwise, vote such Units in favor of, and at the direction of, the Person who is the beneficial owner, and the Partnership shall be entitled to assume it is so acting without further inquiry. The provisions of this Section 13.12(b) (as well as all other provisions of this Agreement) are subject to the provisions of Section 4.3.

ARTICLE XIV

MERGER, CONSOLIDATION OR CONVERSION

Section 14.1 Authority.

The Partnership may merge or consolidate with or into one or more corporations, limited liability companies, statutory trusts or associations, real estate investment trusts, common law trusts or unincorporated businesses, including a partnership (whether general or limited (including a limited liability partnership)) or convert into any such entity, whether such entity is formed under the laws of the State of Delaware or any other state of the United States of America, pursuant to a written plan of merger or consolidation (“Merger Agreement”) or a written plan of conversion (“Plan of Conversion”), as the case may be, in accordance with this Article XIV.

Section 14.2 Procedure for Merger, Consolidation or Conversion.

(a) Merger, consolidation or conversion of the Partnership pursuant to this Article XIV requires the prior consent of the General Partner, provided, however, that, to the fullest extent permitted by law, the General Partner shall have no duty or obligation to consent to any merger, consolidation or conversion of the Partnership and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership, any Limited Partner and, in declining to consent to a merger, consolidation or conversion, shall not be required to act in good faith or pursuant to any other standard imposed by this Agreement, any other agreement contemplated hereby or under the Delaware Act or any other law, rule or regulation or at equity.

(b) If the General Partner shall determine to consent to the merger or consolidation, the General Partner shall approve the Merger Agreement, which shall set forth:

(i) the name and jurisdiction of formation or organization of each of the business entities proposing to merge or consolidate;

(ii) the name and jurisdiction of formation or organization of the business entity that is to survive the proposed merger or consolidation (the “Surviving Business Entity”);

(iii) the terms and conditions of the proposed merger or consolidation;

(iv) the manner and basis of exchanging or converting the equity interests of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the Surviving Business Entity; and (i) if any interests, securities or rights of any constituent business entity are not to be exchanged or converted solely for, or into, cash, property or interests, rights, securities or obligations of the Surviving

 

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Business Entity, then the cash, property or interests, rights, securities or obligations of any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity) which the holders of such interests, securities or rights are to receive in exchange for, or upon conversion of their interests, securities or rights, and (ii) in the case of equity interests represented by certificates, upon the surrender of such certificates, which cash, property or interests, rights, securities or obligations of the Surviving Business Entity or any general or limited partnership, corporation, trust, limited liability company, unincorporated business or other entity (other than the Surviving Business Entity), or evidences thereof, are to be delivered;

(v) a statement of any changes in the constituent documents or the adoption of new constituent documents (the articles or certificate of incorporation, articles of trust, declaration of trust, certificate or agreement of limited partnership, certificate of formation or limited liability company agreement or other similar charter or governing document) of the Surviving Business Entity to be effected by such merger or consolidation;

(vi) the effective time of the merger, which may be the date of the filing of the certificate of merger pursuant to Section 14.4 or a later date specified in or determinable in accordance with the Merger Agreement (provided, that if the effective time of the merger is to be later than the date of the filing of such certificate of merger, the effective time shall be fixed at a date or time certain and stated in the certificate of merger); and

(vii) such other provisions with respect to the proposed merger or consolidation that the General Partner determines to be necessary or appropriate.

(c) If the General Partner shall determine to consent to the conversion, the General Partner shall approve the Plan of Conversion, which shall set forth:

(i) the name of the converting entity and the converted entity;

(ii) a statement that the Partnership is continuing its existence in the organizational form of the converted entity;

(iii) a statement as to the type of entity that the converted entity is to be and the state or country under the laws of which the converted entity is to be incorporated, formed or organized;

(iv) the manner and basis of exchanging or converting the equity securities of each constituent business entity for, or into, cash, property or interests, rights, securities or obligations of the converted entity or another entity, or for the cancellation of such equity securities;

(v) in an attachment or exhibit, the certificate of limited partnership of the Partnership; and

(vi) in an attachment or exhibit, the certificate of limited partnership, articles of incorporation, or other organizational documents of the converted entity;

(vii) the effective time of the conversion, which may be the date of the filing of the articles of conversion or a later date specified in or determinable in accordance with the Plan of Conversion (provided, that if the effective time of the conversion is to be later than the date of the filing of such articles of conversion, the effective time shall be fixed at a date or time certain and stated in such articles of conversion); and

(viii) such other provisions with respect to the proposed conversion that the General Partner determines to be necessary or appropriate.

Section 14.3 Approval by Limited Partners.

(a) Except as provided in Section 14.3(d), the General Partner, upon its approval of the Merger Agreement or the Plan of Conversion, as the case may be, shall direct that the Merger Agreement or the Plan of Conversion and the merger, consolidation or conversion contemplated thereby, as applicable, be submitted to a vote of

 

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Limited Partners, whether at a special meeting or by written consent, in either case in accordance with the requirements of Article XIII. A copy or a summary of the Merger Agreement or the Plan of Conversion, as the case may be, shall be included in or enclosed with the notice of a special meeting or the written consent.

(b) Except as provided in Sections 14.3(d) and 14.3(e), the Merger Agreement or Plan of Conversion, as the case may be, shall be approved upon receiving the affirmative vote or consent of the holders of a Unit Majority unless the Merger Agreement or Plan of Conversion, as the case may be, contains any provision that, if contained in an amendment to this Agreement, the provisions of this Agreement or the Delaware Act would require for its approval the vote or consent of a greater percentage of the Outstanding Units or of any class of Limited Partners, in which case such greater percentage vote or consent shall be required for approval of the Merger Agreement or the Plan of Conversion, as the case may be.

(c) Except as provided in Sections 14.3(d) and 14.3(e), after such approval by vote or consent of the Limited Partners, and at any time prior to the filing of the certificate of merger or certificate of conversion pursuant to Section 14.4, the merger, consolidation or conversion may be abandoned pursuant to provisions therefor, if any, set forth in the Merger Agreement or Plan of Conversion, as the case may be.

(d) Notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to convert the Partnership or any Group Member into a new limited liability entity, to merge the Partnership or any Group Member into, or convey all of the Partnership’s assets to, another limited liability entity that shall be newly formed and shall have no assets, liabilities or operations at the time of such conversion, merger or conveyance other than those it receives from the Partnership or other Group Member if (i) the General Partner has received an Opinion of Counsel that the conversion, merger or conveyance, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (ii) the sole purpose of such conversion, merger, or conveyance is to effect a mere change in the legal form of the Partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the Limited Partners and the General Partner with substantially the same rights and obligations as are herein contained.

(e) Additionally, notwithstanding anything else contained in this Article XIV or in this Agreement, the General Partner is permitted, without Limited Partner approval, to merge or consolidate the Partnership with or into another entity if (A) the General Partner has received an Opinion of Counsel that the merger or consolidation, as the case may be, would not result in the loss of the limited liability under the Delaware Act of any Limited Partner or cause the Partnership or any Group Member to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not already treated as such), (B) the merger or consolidation would not result in an amendment to this Agreement, other than any amendments that could be adopted pursuant to Section 13.1, (C) the Partnership is the Surviving Business Entity in such merger or consolidation, (D) each Unit outstanding immediately prior to the effective date of the merger or consolidation is to be an identical Unit of the Partnership after the effective date of the merger or consolidation, and (E) the number of Partnership Securities to be issued by the Partnership in such merger or consolidation does not exceed 20% of the Partnership Securities (other than Incentive Distribution Rights) Outstanding immediately prior to the effective date of such merger or consolidation.

(f) Pursuant to Section 17-211(g) of the Delaware Act, an agreement of merger or consolidation approved in accordance with this Article XIV may (a) effect any amendment to this Agreement or (b) effect the adoption of a new partnership agreement for the Partnership if it is the Surviving Business Entity. Any such amendment or adoption made pursuant to this Section 14.3 shall be effective at the effective time or date of the merger or consolidation.

 

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Section 14.4 Certificate of Merger.

Upon the required approval by the General Partner and the Unitholders of a Merger Agreement or the Plan of Conversion, as the case may be, a certificate of merger or certificate of conversion, as applicable, shall be executed and filed with the Secretary of State of the State of Delaware in conformity with the requirements of the Delaware Act.

Section 14.5 Effect of Merger, Consolidation or Conversion.

(a) At the effective time of the certificate of merger:

(i) all of the rights, privileges and powers of each of the business entities that has merged or consolidated, and all property, real, personal and mixed, and all debts due to any of those business entities and all other things and causes of action belonging to each of those business entities, shall be vested in the Surviving Business Entity and after the merger or consolidation shall be the property of the Surviving Business Entity to the extent they were of each constituent business entity;

(ii) the title to any real property vested by deed or otherwise in any of those constituent business entities shall not revert and is not in any way impaired because of the merger or consolidation;

(iii) all rights of creditors and all liens on or security interests in property of any of those constituent business entities shall be preserved unimpaired; and

(iv) all debts, liabilities and duties of those constituent business entities shall attach to the Surviving Business Entity and may be enforced against it to the same extent as if the debts, liabilities and duties had been incurred or contracted by it.

(b) At the effective time of the certificate of conversion, for all purposes of the laws of the State of Delaware:

(i) the Partnership shall continue to exist, without interruption, but in the organizational form of the converted entity rather than in its prior organizational form;

(ii) all rights, title, and interests to all real estate and other property owned by the Partnership shall remain vested in the converted entity in its new organizational form without reversion or impairment, without further act or deed, and without any transfer or assignment having occurred, but subject to any existing liens or other encumbrances thereon;

(iii) all liabilities and obligations of the Partnership shall continue to be liabilities and obligations of the converted entity in its new organizational form without impairment or diminution by reason of the conversion;

(iv) all rights of creditors or other parties with respect to or against the prior interest holders or other owners of the Partnership in their capacities as such in existence as of the effective time of the conversion will continue in existence as to those liabilities and obligations and are enforceable against the converted entity by such creditors and obligees to the same extent as if the liabilities and obligations had originally been incurred or contracted by the converted entity;

(v) the Partnership Interests that are to be converted into partnership interests, shares, evidences of ownership, or other rights or securities in the converted entity or cash as provided in the plan of conversion shall be so converted, and Partners shall be entitled only to the rights provided in the Plan of Conversion.

 

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ARTICLE XV

RIGHT TO ACQUIRE LIMITED PARTNER INTERESTS

Section 15.1 Right to Acquire Limited Partner Interests.

(a) Notwithstanding any other provision of this Agreement, if at any time the General Partner and its Affiliates hold more than 80% of the total Limited Partner Interests of any class then Outstanding, the General Partner shall then have the right, which right it may assign and transfer in whole or in part to the Partnership or any Affiliate of the General Partner, exercisable in its sole discretion, to purchase all, but not less than all, of such Limited Partner Interests of such class then Outstanding held by Persons other than the General Partner and its Affiliates, at the greater of (x) the Current Market Price as of the date three days prior to the date that the notice described in Section 15.1(b) is mailed and (y) the highest price paid by the General Partner or any of its Affiliates for any such Limited Partner Interest of such class purchased during the 90-day period preceding the date that the notice described in Section 15.1(b) is mailed.

(b) If the General Partner, any Affiliate of the General Partner or the Partnership elects to exercise the right to purchase Limited Partner Interests granted pursuant to Section 15.1(a), the General Partner shall deliver to the Transfer Agent notice of such election to purchase (the “Notice of Election to Purchase”) and shall cause the Transfer Agent to mail a copy of such Notice of Election to Purchase to the Record Holders of Limited Partner Interests of such class (as of a Record Date selected by the General Partner) at least 10, but not more than 60, days prior to the Purchase Date. Such Notice of Election to Purchase shall also be published for a period of at least three consecutive days in at least two daily newspapers of general circulation printed in the English language and published in the Borough of Manhattan, New York. The Notice of Election to Purchase shall specify the Purchase Date and the price (determined in accordance with Section 15.1(a)) at which Limited Partner Interests will be purchased and state that the General Partner, its Affiliate or the Partnership, as the case may be, elects to purchase such Limited Partner Interests, upon surrender of Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, in exchange for payment, at such office or offices of the Transfer Agent as the Transfer Agent may specify, or as may be required by any National Securities Exchange on which such Limited Partner Interests are listed or admitted to trading. Any such Notice of Election to Purchase mailed to a Record Holder of Limited Partner Interests at his address as reflected in the records of the Transfer Agent shall be conclusively presumed to have been given regardless of whether the owner receives such notice. On or prior to the Purchase Date, the General Partner, its Affiliate or the Partnership, as the case may be, shall deposit with the Transfer Agent cash in an amount sufficient to pay the aggregate purchase price of all of such Limited Partner Interests to be purchased in accordance with this Section 15.1. If the Notice of Election to Purchase shall have been duly given as aforesaid at least 10 days prior to the Purchase Date, and if on or prior to the Purchase Date the deposit described in the preceding sentence has been made for the benefit of the holders of Limited Partner Interests subject to purchase as provided herein, then from and after the Purchase Date, notwithstanding that any Certificate shall not have been surrendered for purchase, all rights of the holders of such Limited Partner Interests (including any rights pursuant to Article III, Article IV, Article V, Article VI, and Article XII) shall thereupon cease, except the right to receive the purchase price (determined in accordance with Section 15.1(a)) for Limited Partner Interests therefor, without interest, upon surrender to the Transfer Agent of the Certificates representing such Limited Partner Interests in the case of Limited Partner Interests evidenced by Certificates, and such Limited Partner Interests shall thereupon be deemed to be transferred to the General Partner, its Affiliate or the Partnership, as the case may be, on the record books of the Transfer Agent and the Partnership, and the General Partner or any Affiliate of the General Partner, or the Partnership, as the case may be, shall be deemed to be the owner of all such Limited Partner Interests from and after the Purchase Date and shall have all rights as the owner of such Limited Partner Interests (including all rights as owner of such Limited Partner Interests pursuant to Article III, Article IV, Article V, Article VI and Article XII).

 

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(c) In the case of Limited Partner Interests evidenced by Certificates, at any time from and after the Purchase Date, a holder of an Outstanding Limited Partner Interest subject to purchase as provided in this Section 15.1 may surrender his Certificate evidencing such Limited Partner Interest to the Transfer Agent in exchange for payment of the amount described in Section 15.1(a), therefor, without interest thereon.

ARTICLE XVI

GENERAL PROVISIONS

Section 16.1 Addresses and Notices; Written Communications.

(a) Any notice, demand, request, report or proxy materials required or permitted to be given or made to a Partner under this Agreement shall be in writing and shall be deemed given or made when delivered in person or when sent by first class United States mail or by other means of written communication to the Partner at the address described below. Any notice, payment or report to be given or made to a Partner hereunder shall be deemed conclusively to have been given or made, and the obligation to give such notice or report or to make such payment shall be deemed conclusively to have been fully satisfied, upon sending of such notice, payment or report to the Record Holder of such Partnership Securities at his address as shown on the records of the Transfer Agent or as otherwise shown on the records of the Partnership, regardless of any claim of any Person who may have an interest in such Partnership Securities by reason of any assignment or otherwise. Notwithstanding the foregoing, if (i) a Partner shall consent to receiving notices, demands, requests, reports or proxy materials via electronic mail or by the Internet or (ii) the rules of the Commission shall permit any report or proxy materials to be delivered electronically or made available via the Internet, any such notice, demand, request, report or proxy materials shall be deemed given or made when delivered or made available via such mode of delivery. An affidavit or certificate of making of any notice, payment or report in accordance with the provisions of this Section 16.1 executed by the General Partner, the Transfer Agent or the mailing organization shall be prima facie evidence of the giving or making of such notice, payment or report. If any notice, payment or report given or made in accordance with the provisions of this Section 16.1 is returned marked to indicate that such notice, payment or report was unable to be delivered, such notice, payment or report and, in the case of notices, payments or reports returned by the United States Postal Service (or other physical mail delivery mail service outside the United States of America), any subsequent notices, payments and reports shall be deemed to have been duly given or made without further mailing (until such time as such Record Holder or another Person notifies the Transfer Agent or the Partnership of a change in his address) or other delivery if they are available for the Partner at the principal office of the Partnership for a period of one year from the date of the giving or making of such notice, payment or report to the other Partners. Any notice to the Partnership shall be deemed given if received by the General Partner at the principal office of the Partnership designated pursuant to Section 2.3. The General Partner may rely and shall be protected in relying on any notice or other document from a Partner or other Person if believed by it to be genuine.

(b) The terms “in writing”, “written communications,” “written notice” and words of similar import shall be deemed satisfied under this Agreement by use of e-mail and other forms of electronic communication.

Section 16.2 Further Action.

The parties shall execute and deliver all documents, provide all information and take or refrain from taking action as may be necessary or appropriate to achieve the purposes of this Agreement.

Section 16.3 Binding Effect.

This Agreement shall be binding upon and inure to the benefit of the parties hereto and their heirs, executors, administrators, successors, legal representatives and permitted assigns.

 

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Section 16.4 Integration.

This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

Section 16.5 Creditors.

None of the provisions of this Agreement shall be for the benefit of, or shall be enforceable by, any creditor of the Partnership.

Section 16.6 Waiver.

No failure by any party to insist upon the strict performance of any covenant, duty, agreement or condition of this Agreement or to exercise any right or remedy consequent upon a breach thereof shall constitute waiver of any such breach of any other covenant, duty, agreement or condition.

Section 16.7 Third-Party Beneficiaries.

Each Partner agrees that (a) any Indemnitee shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Indemnitee and (b) any Unrestricted Person shall be entitled to assert rights and remedies hereunder as a third-party beneficiary hereto with respect to those provisions of this Agreement affording a right, benefit or privilege to such Unrestricted Person.

Section 16.8 Counterparts.

This Agreement may be executed in counterparts, all of which together shall constitute an agreement binding on all the parties hereto, notwithstanding that all such parties are not signatories to the original or the same counterpart. Each party shall become bound by this Agreement immediately upon affixing its signature hereto or, in the case of a Person acquiring a Limited Partner Interest, pursuant to Section 10.1(a) without execution hereof.

Section 16.9 Applicable Law; Forum, Venue and Jurisdiction.

(a) This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware, without regard to the principles of conflicts of law.

(b) Each of the Partners and each Person holding any beneficial interest in the Partnership (whether through a broker, dealer, bank, trust company or clearing corporation or an agent of any of the foregoing or otherwise):

(i) irrevocably agrees that any claims, suits, actions or proceedings (A) arising out of or relating in any way to this Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of this Agreement or the duties, obligations or liabilities among Partners or of Partners to the Partnership, or the rights or powers of, or restrictions on, the Partners or the Partnership), (B) brought in a derivative manner on behalf of the Partnership, (C) asserting a claim of breach of a fiduciary duty owed by any director, officer, or other employee of the Partnership or the General Partner, or owed by the General Partner, to the Partnership or the Partners, (D) asserting a claim arising pursuant to any provision of the Delaware Act or (E) asserting a claim governed by the internal affairs doctrine shall be exclusively brought in the Court of Chancery of the State of Delaware, in each case regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims;

 

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(ii) irrevocably submits to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claim, suit, action or proceeding;

(iii) agrees not to, and waives any right to, assert in any such claim, suit, action or proceeding that (A) it is not personally subject to the jurisdiction of the Court of Chancery of the State of Delaware or of any other court to which proceedings in the Court of Chancery of the State of Delaware may be appealed, (B) such claim, suit, action or proceeding is brought in an inconvenient forum, or (C) the venue of such claim, suit, action or proceeding is improper;

(iv) expressly waives any requirement for the posting of a bond by a party bringing such claim, suit, action or proceeding; and

(v) consents to process being served in any such claim, suit, action or proceeding by mailing, certified mail, return receipt requested, a copy thereof to such party at the address in effect for notices hereunder, and agrees that such services shall constitute good and sufficient service of process and notice thereof; provided, nothing in clause (v) hereof shall affect or limit any right to serve process in any other manner permitted by law.

Section 16.10 Invalidity of Provisions.

If any provision or part of a provision of this Agreement is or becomes for any reason, invalid, illegal or unenforceable in any respect, the validity, legality and enforceability of the remaining provisions and part thereof contained herein shall not be affected thereby and this Agreement shall, to the fullest extent permitted by law, be reformed and construed as if such invalid, illegal or unenforceable provision, or part of a provision, had never been contained herein, and such provision or part reformed so that it would be valid, legal and enforceable to the maximum extent possible.

Section 16.11 Consent of Partners.

Each Partner hereby expressly consents and agrees that, whenever in this Agreement it is specified that an action may be taken upon the affirmative vote or consent of less than all of the Partners, such action may be so taken upon the concurrence of less than all of the Partners and each Partner shall be bound by the results of such action.

Section 16.12 Facsimile Signatures.

The use of facsimile signatures affixed in the name and on behalf of the transfer agent and registrar of the Partnership on Certificates representing Units is expressly permitted by this Agreement.

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IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.

 

 

 

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FIRST AMENDED AND RESTATED AGREEMENT

OF LIMITED PARTNERSHIP OF CHESAPEAKE MIDSTREAM PARTNERS, L.P.

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EXHIBIT A

to the First Amended and Restated

Agreement of Limited Partnership of

Chesapeake Midstream Partners, L.P.

Certificate Evidencing Common Units

Representing Limited Partner Interests in

Chesapeake Midstream Partners, L.P.

 

No.	Common Units

In accordance with Section 4.1 of the First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P., as amended, supplemented or restated from time to time (the “Partnership Agreement”), Chesapeake Midstream Partners, L.P., a Delaware limited partnership (the “Partnership”), hereby certifies that                      (the “Holder”) is the registered owner of                              Common Units representing limited partner interests in the Partnership (the “Common Units”) transferable on the books of the Partnership, in person or by duly authorized attorney, upon surrender of this Certificate properly endorsed. The rights, preferences and limitations of the Common Units are set forth in, and this Certificate and the Common Units represented hereby are issued and shall in all respects be subject to the terms and provisions of, the Partnership Agreement. Copies of the Partnership Agreement are on file at, and will be furnished without charge on delivery of written request to the Partnership at, the principal office of the Partnership located at 777 NW Grand Boulevard, Oklahoma City, Oklahoma 73118. Capitalized terms used herein but not defined shall have the meanings given them in the Partnership Agreement.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE CHESAPEAKE MIDSTREAM PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). CHESAPEAKE MIDSTREAM GP, L.L.C., THE GENERAL PARTNER OF CHESAPEAKE MIDSTREAM PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF CHESAPEAKE MIDSTREAM PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES. THE RESTRICTIONS SET FORTH ABOVE SHALL NOT PRECLUDE THE SETTLEMENT OF ANY TRANSACTIONS INVOLVING THIS SECURITY ENTERED INTO THROUGH THE FACILITIES OF ANY NATIONAL SECURITIES EXCHANGE ON WHICH THIS SECURITY IS LISTED OR ADMITTED TO TRADING.

The Holder, by accepting this Certificate, is deemed to have (i) requested admission as, and agreed to become, a Limited Partner and to have agreed to comply with and be bound by and to have executed the Partnership Agreement, (ii) represented and warranted that the Holder has all right, power and authority and, if an individual, the capacity necessary to enter into the Partnership Agreement and (iii) made the waivers and given the consents and approvals contained in the Partnership Agreement.

 

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This Certificate shall not be valid for any purpose unless it has been countersigned and registered by the Transfer Agent and Registrar. This Certificate shall be governed by and construed in accordance with the laws of the State of Delaware.

 

Dated:						Chesapeake Midstream Partners, L.P.
Countersigned and Registered by:						By: Chesapeake Midstream GP, L.L.C.
Computershare Trust Company, N.A., As Transfer Agent and Registrar						By:
						Name:
						By:
								Secretary

 

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[Reverse of Certificate]

ABBREVIATIONS

The following abbreviations, when used in the inscription on the face of this Certificate, shall be construed as follows according to applicable laws or regulations:

 

TEN COM -as tenants in common TEN ENT - as tenants by the entireties JT TEN -      as joint tenants with right of survivorship and not as tenants in common		UNIF GIFT/TRANSFERS MIN ACT                          Custodian                      (Cust)                                   (Minor) Under Uniform Gifts/Transfers to CD Minors Act (State)

Additional abbreviations, though not in the above list, may also be used.

ASSIGNMENT OF COMMON UNITS OF

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

FOR VALUE RECEIVED,                      hereby assigns, conveys, sells and transfers unto

(Please print or typewrite name and address of assignee)				(Please insert Social Security or other identifying number of assignee)

                     Common Units representing limited partner interests evidenced by this Certificate, subject to the Partnership Agreement, and does hereby irrevocably constitute and appoint                      as its attorney-in-fact with full power of substitution to transfer the same on the books of Chesapeake Midstream Partners, L.P.

 

Date:				NOTE: The signature to any endorsement hereon must correspond with the name as written upon the face of this Certificate in every particular. without alteration, enlargement or change.
THE SIGNATURE(S) MUST BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCKBROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PURSUANT TO S.E.C. RULE 17Ad-15
				(Signature)
				(Signature)

No transfer of the Common Units evidenced hereby will be registered on the books of the Partnership, unless the Certificate evidencing the Common Units to be transferred is surrendered for registration or transfer.

 

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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. With respect to a quarter in which a shortfall amount is actually paid, adjusted operating surplus shall be reduced by an amount equal to the amount of quarterly shortfall payment estimates previously added by the general partner to adjusted operating surplus with respect to such minimum volume commitment period.

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;

 

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(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

(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;

 

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(b) sales of equity interests by Chesapeake Midstream Partners, L.P. or any of its subsidiaries;

(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) capital contributions; and

(e) 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 and its affiliates, payments made in the ordinary course of business under interest rate swap 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 commodity hedge contract, such amounts shall be amortized over the life of the applicable 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 shall be included in equal quarterly installments over the remaining scheduled life of such hedge contract), 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 penultimate 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

 

•

repurchases of equity interests except to fund obligations under employee benefit plans.

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,

 

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•

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 before the date of determination of operating surplus for the quarter; plus

 

•

cash distributions paid on equity issued (including incremental distributions on incentive distribution rights) to finance all or a portion of the construction, acquisition, improvement of a capital improvement or replacement of a capital asset (such as equipment or facilities) in respect of 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; less

 

•

any loss realized on disposition of an investment capital expenditure.

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.

 

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                     Common Units

Representing Limited Partner Interests

 

 

Joint Book-Running Managers

UBS Investment Bank    Citi    Morgan Stanley

BofA Merrill Lynch    Barclays Capital    Credit Suisse    Goldman, Sachs & Co.    Wells Fargo Securities

Senior Co-Managers

BBVA Securities    BMO Capital Markets    Deutsche Bank Securities    Raymond James     RBS    Scotia Capital

Junior Co-Managers

BNP PARIBAS    Comerica Securities    Credit Agricole CIB    ING    Mitsubishi UFJ Securities

Piper Jaffray    RBC Capital Markets     SunTrust Robinson Humphrey    TD Securities

 

 

 

 

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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		$	34,849
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		$	3,000,000

 

*	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;

 

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any departing general partner;

 

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any person who is or was an affiliate of our general partner or any departing general partner;

 

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any person who is or was a manager, managing member, director, officer, employee, agent, fiduciary or trustee of our partnership, our subsidiaries, our general partner, any departing general partner or any of their affiliates;

 

•

any person who is or was serving as a manager, managing member, director, officer, employee, agent, fiduciary or trustee of another person owing a fiduciary duty to us or our subsidiaries;

 

•

any person who controls our general partner or any departing general partner; 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 Midstream Ventures for certain liabilities. The section of the prospectus entitled “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Omnibus Agreement” describes in more detail indemnification obligations under the omnibus agreement and is incorporated herein by reference.

Pursuant to the services agreement, we and our affiliates will be entitled to indemnification for certain liabilities, and we will be required to indemnify certain affiliates of Chesapeake. The section of the prospectus entitled “Certain Relationships and Related Party Transactions—Agreements with Affiliates—Services Agreement” describes in more detail indemnification obligations under the services agreement and is incorporated herein by reference.

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

 

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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.

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.

 

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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.

 

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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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 MLP Operating, 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**†		—		Additional Agreement
10.5*		—		Form of Contribution Agreement
10.6*		—		Form of Omnibus Agreement
10.7*		—		Form of Services Agreement
10.8**†		—		Form of Gas Compressor Master Rental and Servicing Agreement
10.9*		—		Form of Employee Transfer Agreement
10.10*		—		Form of Employee Secondment Agreement
10.11*		—		Form of Shared Services Agreement with respect to J. Mike Stice
10.12*		—		Amended and Restated Employment Agreement of J. Mike Stice
10.13*		—		Amendment to Employment Agreement of J. Mike Stice
10.14*		—		Employment Agreement of Robert S. Purgason
10.15*		—		Employment Agreement of David C. Shiels
10.16*		—		Form of Registration Rights Agreement
10.17*		—		Form of Chesapeake Midstream Management Incentive Compensation Plan
10.18*		—		Form of Chesapeake Midstream Long-Term Incentive Plan
10.19*		—		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.

**	Previously filed.

†	Portions of this exhibit, filed previously, have been omitted pursuant to a request for confidential treatment.

 

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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 the purpose of determining liability under the Securities Act to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A, shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness. Provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(2) For the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities, the undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

 

i.

Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

 

ii.

Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

 

iii.

The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

 

iv.

Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(3) 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.

 

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(4) 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 May 24, 2010.

 

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. MIKE STICE J. Mike Stice		Chief Executive Officer (Principal Executive Officer)		May 24, 2010
/s/ DAVID C. SHIELS David C. Shiels		Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)		May 24, 2010
* Matthew C. Harris		Director		May 24, 2010
* Aubrey K. McClendon		Director		May 24, 2010
* Marcus C. Rowland		Director		May 24, 2010
* William A. Woodburn		Director		May 24, 2010

 

*By:		/s/ J. MIKE STICE
		J. Mike Stice, Attorney-in-Fact

 

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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 MLP Operating, 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**†		—		Additional Agreement
10.5*		—		Form of Contribution Agreement
10.6*		—		Form of Omnibus Agreement
10.7*		—		Form of Services Agreement
10.8**†		—		Form of Gas Compressor Master Rental and Servicing Agreement
10.9*		—		Form of Employee Transfer Agreement
10.10*		—		Form of Employee Secondment Agreement
10.11*		—		Form of Shared Services Agreement with respect to J. Mike Stice
10.12*		—		Amended and Restated Employment Agreement of J. Mike Stice
10.13*		—		Amendment to Employment Agreement of J. Mike Stice
10.14*		—		Employment Agreement of Robert S. Purgason
10.15*		—		Employment Agreement of David C. Shiels
10.16*		—		Form of Registration Rights Agreement
10.17*		—		Form of Chesapeake Midstream Management Incentive Compensation Plan
10.18*		—		Form of Chesapeake Midstream Long-Term Incentive Plan
10.19*		—		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.

**	Previously filed.

†	Portions of this exhibit, filed previously, have been omitted pursuant to a request for confidential treatment.

 

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