Williams Partners 10-Q 2010 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x Quarterly Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended September 30, 2010

¨ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                        to                        

Commission File No. 1-34831

Chesapeake Midstream Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)

Delaware	80-0534394
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

777 NW Grand Boulevard
Oklahoma City, Oklahoma	73118
(Address of principal executive offices)	(Zip Code)

(405) 935-1500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [ ] No [ ]

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  x    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨    No  x

As of November 8, 2010, the registrant had 69,083,265 common units outstanding.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

INDEX TO FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2010

		Page
	PART I.
Financial Information
Item 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		1
	Condensed Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		3
	Condensed Consolidated Statement of Changes in Equity for the Nine Months Ended September 30, 2010		4
	Notes to Condensed Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		26
Item 4.	Controls and Procedures		27
	PART II.
Other Information
Item 1.	Legal Proceedings		28
Item 1A.	Risk Factors		28
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3.	Defaults Upon Senior Securities		28
Item 4.	(Removed and Reserved)		28
Item 5.	Other Information		28
Item 6.	Exhibits		29

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

	September 30, 2010			December 31, 2009
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	309,130		$	3
Accounts receivable, including $27,623 and $165,065 from related parties at September 30, 2010 and December 31, 2009, respectively		35,674			165,771
Other current assets		3,351			1,743
Total current assets		348,155			167,517
Property, plant and equipment:
Gathering systems		2,155,868			2,013,347
Other fixed assets		35,588			34,130
Less: Accumulated depreciation		(335,231	)		(271,062	)
Total property, plant and equipment, net		1,856,225			1,776,415
Deferred loan costs, net		15,798			14,743
Total assets	$	2,220,178		$	1,958,675
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	35,163		$	22,940
Accrued liabilities, including $30,902 and $84,708 due to related parties at September 30, 2010 and December 31, 2009, respectively		45,250			95,158
Total current liabilities		80,413			118,098
Long-term liabilities:
Revolving bank credit facility		—			44,100
Other liabilities		4,127			2,850
Total long-term liabilities		4,127			46,950
Commitments and contingencies (Note 9)
Equity:
Common units (69,083,265 issued and outstanding at September 30, 2010)		1,256,960			—
Subordinated units (69,076,122 issued and outstanding at September 30, 2010)		844,220			—
General partner units (2,819,434 issued and outstanding at September 30, 2010)		34,458			—
Members’ equity		—			1,793,627
Total equity		2,135,638			1,793,627
Total liabilities and equity	$	2,220,178		$	1,958,675

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

1

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

				Predecessor						Predecessor
	Three Months Ended September 30, 2010			Three Months Ended September 30, 2009			Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
	($ in thousands, except per unit data)
Revenues, including revenue from affiliates (Note 7)	$	100,060		$	131,258		$	296,685		$	358,921
Operating Expenses:
Operating expenses, including expenses from affiliates (Note 8)		34,094			52,127			97,172			146,604
Depreciation and amortization expense		23,785			24,153			69,177			65,477
General and administrative expense, including expenses from affiliates (Note 8)		7,098			12,113			21,221			22,782
Impairment of property, plant and equipment and other assets		—			90,207			—			90,207
Loss on sale of assets		323			43,980			256			44,566
Total operating expenses		65,300			222,580			187,826			369,636
Operating income (loss)		34,760			(91,322	)		108,859			(10,715	)
Other Income (Expense):
Interest expense (Note 5)		(681	)		(126	)		(1,818	)		(347	)
Other income		34			11			76			29
Income (loss) before income tax expense		34,113			(91,437	)		107,117			(11,033	)
Income tax expense		699			2,070			1,772			6,341
Net income (loss)	$	33,414		$	(93,507	)	$	105,345		$	(17,374	)
Limited partner interest in net income
Net income(1)	$	19,514			N/A		$	19,514			N/A
Less general partner interest in net income		(390	)		N/A			(390	)		N/A
Limited partner interest in net income	$	19,124			N/A		$	19,124			N/A
Net income per common unit – basic and diluted	$	0.14			N/A		$	0.14			N/A
Net income per subordinated unit – basic and diluted	$	0.14			N/A		$	0.14			N/A

⁽¹⁾ Reflective of general and limited partner interest in net income since closing the Partnership’s initial public offering on August 3, 2010. See Note 4 to the condensed consolidated financial statements.

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

2

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

				Predecessor
	Nine Months Ended September 30, 2010			Nine Months Ended September 30, 2009
	($ in thousands)
Cash flows from operating activities:
Net income	$	105,345		$	(17,374	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		69,177			65,477
Deferred income taxes		—			6,341
Impairment of property, plant and equipment and other assets		—			90,207
Loss on sale of assets		256			44,566
Other non-cash items		99			(282	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		129,592			(29,553	)
Increase in other assets		(1,608	)		(1,901	)
Increase (decrease) in accounts payable		10,129			(82,112	)
Increase (decrease) in accrued liabilities		(45,870	)		25,379
Net cash provided by operating activities		267,120			100,748
Cash flows from investing activities:
Additions to property, plant and equipment		(156,463	)		(756,883	)
Proceeds from sale of assets		4,416			65,889
Net cash used in investing activities		(152,047	)		(690,994	)
Cash flows from financing activities:
Proceeds from long-term debt borrowings		252,300			870,373
Payments on long-term debt borrowings		(296,400	)		(1,318,200	)
Proceeds from issuance of common units, net of offering costs		475,009			—
Distributions to partners		(231,919	)		(10,153	)
Contribution from Predecessor		177			—
Contributions from Chesapeake		—			567,828
Proceeds from sale of noncontrolling interest		—			587,500
Joint venture transaction costs		—			(16,130	)
Debt issuance cost		(5,113	)		(16,950	)
Net cash provided by financing activities		194,054			664,268
Net increase in cash and cash equivalents		309,127			74,022
Cash and cash equivalents, beginning of period		3			82,025
Cash and cash equivalents, end of period	$	309,130		$	156,047
Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	5,522		$	(52,521	)
Changes in other liabilities related to asset retirement obligations	$	(101	)	$	(2,893	)
Contributions of property, plant and equipment to (from) Chesapeake	$	11,705		$	(91,462	)
Supplemental disclosure of cash payments for interest	$	2,765		$	7,478

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

3

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)

				Partners’ Equity
				Limited Partners
	Members’ Equity			Common			Subordinated		General Partner		Total
	($ in thousands)
Balance at December 31, 2009	$	1,793,627		$	—		$	—	$	—	$	1,793,627
Distributions to Predecessor, net		(6,574	)		—			—		—		(6,574	)
Distributions to members		(169,500	)		—			—		—		(169,500	)
Net income attributable to the period from January 1, 2010 through August 2, 2010		85,831			—			—		—		85,831
Contribution of net assets to Chesapeake Midstream Partners, L.P.		(1,703,384	)		834,658			834,658		34,068		—
Issuance of common units to public, net of offering and other costs		—			475,009			—		—		475,009
Distribution of proceeds to partner from exercise of over-allotment option		—			(62,419	)		—		—		(62,419	)
Non-cash equity based compensation		—			150			—		—		150
Net income attributable to the period from August 3, 2010 through September 30, 2010		—			9,562			9,562		390		19,514
Balance at September 30, 2010	$	—		$	1,256,960		$	844,220	$	34,458	$	2,135,638

4

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Description of Business

Organization

Chesapeake Midstream Partners, L.P., (the “Partnership”) a Delaware limited partnership formed in January 2010, is 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. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”) and Total Gas and Power North America, Inc. (“Total”), the Partnership’s primary customers, and other third-party producers under long-term, fixed-fee contracts.

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 assets of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of 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.

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, L.L.C., and certain of their respective subsidiaries and affiliates (“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.

The assets contributed to the joint venture and ultimately the Partnership 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 2,900 miles of gathering pipeline, eight small hydrocarbon dew point control facilities, and two CO₂/H₂S extraction 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 (including other areas in the Appalachian Basin) and the Eagle Ford Shale.

On August 3, 2010, the Partnership completed its initial public offering (the “Offering”) of 24,437,500 common units (such amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at a price of $21 per unit. The common units are listed on the New York Stock Exchange (the “NYSE”) under the symbol “CHKM”.

The Partnership received gross offering proceeds of approximately $513.2 million less approximately $38.2 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. The Partnership used the net offering proceeds of $412.6 million to repay approximately $110.0 million of borrowings under its revolving credit facility and to pay approximately $5.1 million of fees related to the amendment of its revolving credit facility. The remainder is expected to be used to fund expansion capital expenditures (see definition of expansion capital expenditures under the heading “Capital Requirements”in Part I, Items 2 of this Form 10-Q) and acquisitions.

Following the close of the Offering, the Partnership had outstanding 69,076,122 common units, 69,076,122 subordinated units, a 2% general partner interest and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase above specified levels. Common units held by public security holders represent 17.7% of all outstanding limited partner interests, and Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, hold a 98.0% limited partner interest in the Partnership and the general partner, which is owned and controlled by Chesapeake and GIP, holds a 2.0% general partner interest in the Partnership.

5

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Concurrent with the closing of the Offering, Chesapeake and GIP contributed Successor to the Partnership by conveying a 100% membership interest in Chesapeake MLP Operating, L.L.C., which owned all of the Partnership’s assets since September 2009.

2. Basis of Presentation

For ease of reference, the Partnership refers to the historical financial results of Successor prior to the Offering as being “our” historical financial results. Unless the context otherwise requires, references to “our assets,” “our systems” and similar descriptions of the Partnership’s business and operations relate only to the portion of our Predecessor (represented by Successor) that were contributed to the Partnership at the closing of the Offering.

The accompanying unaudited condensed consolidated financial statements are presented for current and Predecessor periods, which relate to the accounting periods preceding and succeeding the September 30, 2009 joint venture transaction described in Note 1. The current and Predecessor periods have been separated by a vertical line on the face of the unaudited 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 condensed consolidated balance sheets and changes in members’ equity of the Partnership as of September 30, 2010 and December 31, 2009. They also include the unaudited condensed consolidated statements of operations for the Partnership for the three and nine month periods ended September 30, 2010, and for our Predecessor for the three and nine month periods ended September 30, 2009, and the unaudited condensed consolidated cash flows of the Partnership for the nine month period ended September 30, 2010 and of our Predecessor for the nine months ended September 30, 2009.

The accompanying unaudited condensed consolidated financial statements were prepared using accounting principles generally accepted in the United States (“GAAP”) for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). 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. Certain footnote disclosures normally included in the financial statements prepared in accordance with GAAP have been appropriately condensed or omitted in this quarterly report on Form 10-Q (this “Form 10-Q”). Management believes the disclosures made are adequate to make the information presented not misleading. This Form 10-Q should be read together with the Partnership’s prospectus dated July 28, 2010 and filed with the SEC on July 30, 2010 pursuant to Rule 424(b)(4) of the Securities Act of 1933.

The results of operations for the three and nine month periods ended September 30, 2010 are not indicative of results that may be expected for the full fiscal year.

3. Partnership Equity and Distributions

The partnership agreement requires that, within 45 days subsequent to the end of each quarter, the Partnership distribute its available cash (as defined in the partnership agreement) to unitholders of record on the applicable record date. See Note 10 concerning the distribution approved in October 2010.

General Partner Interest and Incentive Distribution Rights

The general partner of the Partnership is currently entitled to two percent of all quarterly distributions that the Partnership makes. Upon the issuance of any equity by the Partnership, the general partner has the right, but not the obligation, to contribute a proportionate amount of capital to the Partnership to maintain its current general partner interest. The general partner’s two percent interest in all cash distributions will be reduced if the Partnership issues additional units in the future and the general partner does not contribute a proportionate amount of capital to the Partnership to maintain its two percent interest.

6

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The general partner currently holds IDRs that entitle it to receive increasing percentages, up to a maximum of 50 percent, of Partnership cash distributions if any of the Partnership’s quarterly distributions exceed a specified threshold. The maximum distribution sharing percentage of 50 percent includes distributions paid to the general partner on its two percent general partner interest and assumes that the general partner maintains its general partner interest at two percent. The maximum distribution of 50 percent does not include any distributions that the general partner may receive on the limited partner units that it may acquire.

Subordinated Units

All subordinated units are held indirectly by Chesapeake and GIP. These units are considered subordinated because for a period of time (the “Subordination Period”), the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution of $0.3375 per common unit plus any arrearages from prior quarters. The partnership agreement provides that, during the Subordination Period, the common units are entitled to distributions of available cash each quarter in an amount equal to 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 are permitted on the subordinated units. Furthermore, arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the Subordination Period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

The Subordination Period will lapse at such time when the Partnership has paid at least $0.3375 per quarter on each common unit, subordinated unit and general partner unit for any three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2013. Also, if the Partnership has paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit for each calendar quarter in a four-quarter period, the Subordination Period will terminate automatically. Each of these events must coincide with the Partnership’s adjusted operating surplus (as defined in the partnership agreement) during the four-quarter period immediately preceding the termination generating at least $2.025 (150 percent of the annualized minimum quarterly distribution) on all of the common and subordinated units on a fully diluted weighted average basis and the related distributions on the general partner interest and IDRs.

The Subordination Period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the Subordination Period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Successor Distribution

On May 4, 2010, Successor paid a distribution of $150 million. The distribution was funded through cash on hand and borrowings under Successor’s amended revolving credit facility and consisted of $75 million payments to each of Chesapeake and GIP.

4. Net Income per Limited Partner Unit

The Partnership’s net income is allocated to the general partner and the limited partners, including any subordinated unitholders, in accordance with their respective ownership percentages, and, when applicable, giving effect to unvested units granted under the Chesapeake Midstream Long-Term Incentive Plan (the “LTIP”) and incentive distributions allocable to the general partner. The Partnership’s net income allocable to the limited partners is allocated between the common and subordinated unitholders by applying the provisions of the partnership agreement that govern actual cash distributions as if all earnings for the period had been distributed.

7

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Basic and diluted net income per limited partner unit is calculated by dividing the limited partners’ interest in net income by the weighted average number of limited partner units outstanding during the period. The common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.

The following table illustrates the Partnership’s calculation of net income per unit for common and subordinated limited partner units (in thousands, except per-unit information):

	August 3, 2010 to September 30, 2010
Net income (from close of the Offering on August 3, 2010 to September 30, 2010)	$	19,514
Less general partner interest in net income		(390	)
Limited partner interest in net income	$	19,124
Net income allocable to common units	$	9,562
Net income allocable to subordinated units		9,562
Limited partner interest in net income	$	19,124
Net income per limited partner unit – basic and diluted
Common units	$	0.14
Subordinated units		0.14
Total	$	0.14
Weighted average limited partner units outstanding – basic and diluted
Common units		69,083,265
Subordinated units		69,076,122
Total		138,159,387

5. Revolving Bank Credit Facilities

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 its existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under our Predecessor’s 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 of debt issuance costs associated with the $500 million credit facility.

8

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

In connection with the Offering, the Partnership further amended Successor’s revolving bank credit facility, which will now mature in June 2015. As amended, the credit facility provides up to $750 million of borrowing capacity and includes a sub-limit of $25 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility. Borrowings under the credit facility are secured by all of the assets of the Partnership and its subsidiaries, and loans thereunder (other than swing line loans) bear interest at the Partnership’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 is subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent consolidated leverage ratio. The unused portion of the credit facility is subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. At September 30, 2010 there were no outstanding borrowings under such credit facility and at December 31, 2009 there were $44.1 million of outstanding borrowings under such credit facility.

The Partnership’s amended credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined in the amended credit facility agreement) of not more than 4.50 to 1, and an EBITDA to interest expense ratio (as defined in the amended credit facility agreement) of not less than 3.00 to 1. The Partnership was in compliance with all covenants under the agreement at September 30, 2010.

Additionally, the credit facility contains various covenants and restrictive provisions which, among other things, limits the ability of the Partnership and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. If the Partnership fails 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 credit facility could be declared immediately due and payable. The credit facility agreement also has cross default provisions that apply to any other indebtedness the Partnership has 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 September 30, 2010 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

Capitalized Interest

For the three and nine months ended September 30, 2010, interest expense was net of capitalized interest of $0.4 million and $1.9 million, respectively, for the Partnership, and $2.7 million and $6.5 million for the three and nine month periods ended September 30, 2009, respectively, for our Predecessor.

6. Equity-Based Compensation

Certain employees of Chesapeake have been seconded to the Partnership to provide operating, routine maintenance and other services with respect to the business under the direction, supervision and control of the Partnership’s general partner. A number of these employees receive equity-based compensation through Chesapeake’s stock-based compensation programs, which consist of restricted stock issued to employees.

9

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 Partnership’s 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 Partnership and our Predecessor and are reflected as operating expenses. Included in operating expenses is stock-based compensation of $0.5 million and $1.4 million for the Partnership during the three and nine month periods ended September 30, 2010, respectively, and $1.8 million and $5.3 million for our Predecessor during the three and nine month periods ended September 30, 2009, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership and our Predecessor through an overhead allocation and are reflected as general and administrative expenses.

Concurrent with closing of the Offering, awards of Partnership units with a value of approximately $50,000 per award were made to each of the three independent directors of the Partnership’s general partner pursuant to the LTIP in connection with their initial appointment to the Board of Directors of the Partnership’s general partner. The LTIP provides for an aggregate of 3,500,000 common units to be awarded to employees, directors and consultants of the Partnership’s general partner and its affiliates through various award types, including unit awards, restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards. 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 employees, directors and consultants.

7. Major Customers and Concentration of Credit Risk

Financial instruments that potentially subject the Partnership and our Predecessor to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On September 30, 2010 and December 31, 2009, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.

CEMI accounted for $80.5 million and $244.3 million of the Partnership’s revenues for the three and nine month periods ended September 30, 2010, respectively, and $126.6 million and $350.4 million of our Predecessor’s revenues for the three and nine month periods ended September 30, 2009, respectively. Total accounted for $15.8 million and $42.5 million of the Partnership’s revenues for the three and nine months ended September 30, 2010, respectively, and accounted for none of our Predecessor’s revenues for both the three and nine month periods ended September 30, 2009. Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., have a joint venture arrangement in which Total E&P USA, Inc. holds a 25% non-operated interest in Chesapeake’s Barnett Shale upstream assets.

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.

10

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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 unaudited condensed consolidated financial statements for Successor and our Predecessor 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 October 15, 2008, 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 an 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 Partnership 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 are charged to the Partnership based on actual cost of the services provided, subject to a fee per mcf cap based on volumes of natural gas gathered. The fee is calculated as the lesser of $0.03/mcf gathered or actual corporate overhead costs. General and administrative charges were $4.1 million and $12.5 million for the three and nine month periods ended September 30, 2010, respectively, for the Partnership, and $6.2 million and $14.6 million for the three and nine month periods ended September 30, 2009, respectively, for our Predecessor.

Chesapeake and its affiliates also provide compression services. Monthly compressor rentals were charged to our Predecessor under short-term contracts at market rates. The Partnership is charged for compressor rentals based on a long-term compressor rental agreement with Chesapeake and its subsidiaries. For the three and nine month periods ended September 30, 2010, compressor rental charges from affiliates were $11.9 million and $35.0 million, respectively, for the Partnership. For the three and nine month periods ended September 30, 2009, compressor rental charges from affiliates were $16.2 million and $47.2 million, respectively, for our Predecessor. These charges are included in operating expenses in the accompanying unaudited condensed consolidated statements of operations.

9. Commitments and Contingencies

Certain 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 September 30, 2010 or December 31, 2009.

10. Subsequent Events

On October 26, 2010, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.2165 per unit together with the corresponding distribution to the general partner. This amount represents a minimum quarterly distribution prorated for the 59-day period beginning on August 3, 2010 and ending on September 30, 2010. The cash distribution was paid on November 12, 2010 to unitholders of record on November 5, 2010 and to the general partner.

11

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The historical unaudited condensed consolidated financial statements reflect the assets, liabilities and operations of Chesapeake Midstream Development, L.P. (our “Predecessor”) (for periods ending on or before September 30, 2009) and of the successor to our Predecessor (“Successor”) (for periods ending after September 30, 2009). On September 30, 2009, Chesapeake Energy Corporation (“Chesapeake”) and Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates (“GIP”) formed Successor in a joint venture transaction to own and operate a portion of the business of our Predecessor consisting of certain assets and operations that have historically been 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. On August 3, 2010, Chesapeake and GIP contributed Successor to Chesapeake Midstream Partners, L.P. (the “Partnership”) by conveying a 100% membership interest in Chesapeake MLP Operating, L.L.C. to the Partnership. On this date, the Partnership also closed its initial public offering (“the Offering”) of common units representing limited partner interests.

For ease of reference, we refer to the historical financial results of Successor prior to the Offering as being “our” historical financial results. 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) that were contributed to us at the closing of the Offering.

Overview

The following table sets forth certain information regarding revenues, operating expenses, other income and expenses, key performance metrics and operational data for the Partnership for the three and nine months ended September 30, 2010 (the “Current Quarter” and the “Current Period”, respectively):

	Three Months Ended September 30, 2010			Nine Months Ended September 30, 2010
	(In thousands, except operational data)
Revenues(1)	$	100,060		$	296,685
Operating expenses		34,094			97,172
Depreciation and amortization expense		23,785			69,177
General and administrative expense		7,098			21,221
(Gain) loss on sale of assets		323			256
Total operating expenses		65,300			187,826
Operating income		34,760			108,859
Interest expense		(681	)		(1,818	)
Other income		34			76
Income before income tax expense		34,113			107,117
Income tax expense		699			1,772
Net income	$	33,414		$	105,345
Key Performance Metrics:
Adjusted EBITDA(2)	$	58,902		$	178,368
Distributable cash flow(2)	$	40,022		$	122,278
Operational Data:
Wells connected during period		121			301
Wells connected at end of period		4,065			4,065
Throughput, mmcf per day		1,584			1,580
Miles of pipe at end of period		2,890			2,890
Gas compression (horsepower) at end of period		219,900			219,900

12

(1) In the event either Chesapeake or Total Gas and Power North America, Inc. does not meet its minimum volume commitment to us in our Barnett Shale region under our gas gathering agreements, as adjusted in certain circumstances, 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. Should payments be due under the minimum volume commitment with respect to any year, we recognize the associated revenue in the fourth quarter of that year.

(2) Adjusted EBITDA and distributable cash flow are defined below under the captionHow We Evaluate Our Operations within this Part I, Item 2. Reconciliations of Adjusted EBITDA and distributable cash flow to their most directly comparable measures calculated and presented in accordance with GAAP are included under the captionResults of Operations within this Part I, Item 2.

We are a limited partnership formed 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 Gas and Power North America, Inc. (“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 1,800 wells in the core of the 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 2,900 miles of gathering pipelines, servicing approximately 4,100 natural gas wells. For both the Current Quarter and Current Period, our assets gathered approximately 1.6 bcf of natural gas per day.

We generated approximately 75% of our revenues from our gathering systems in our Barnett Shale region for both the Current Quarter and Current Period and approximately 25% of our revenues from our gathering systems in our Mid-Continent region for both the Current Quarter and Current Period.

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, an affiliate of Chesapeake’s upstream joint venture partner in the Barnett Shale, Total E&P USA, Inc. (“Total E&P”). Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to dedicate extensive acreage in our Barnett Shale region and Chesapeake has agreed to dedicate extensive acreage in our Mid-Continent region. These agreements generally require us to connect Chesapeake and Total operated natural gas drilling pads and wells within our acreage dedications to our gathering systems and contain the following terms that are intended to support the stability of our cash flows: (i) 10-year minimum volume commitments in our Barnett Shale region, which mitigate throughput volume variability; (ii) fee redetermination mechanisms in our Barnett Shale and Mid-Continent regions, which are designed to support a return on our invested capital and allow our gathering rates to be adjusted, subject to specified caps, to account for variability in revenues, capital expenditures and compression expenses; and (iii) price escalators in our Barnett Shale and Mid-Continent regions, which annually increase our gathering rates.

Our Gas Gathering Agreements

We are party to (i) a 20-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into in connection with the joint venture 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 E&P in January 2010.

Future revenues under our gas gathering agreements will be derived pursuant to terms that will differ between our two 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.

13

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 received 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 natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region.

• 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 commitment will be attributed to Chesapeake, and approximately 25% will be attributed to Total. The minimum volume commitments increase, on average, approximately 3% per year. 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 commitments 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 final day of 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 forecast as of the redetermination date and scheduled estimates thereof 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.

14

• 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 and Total, 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.

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 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.

• 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 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 dedications 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 its volumes. Although we have not yet agreed on a cap with Chesapeake and Total, 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.

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 in 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.

15

Other Arrangements

Business Opportunities.Pursuant to our omnibus agreement with Chesapeake, 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.

Services Arrangements.Under our services agreement with Chesapeake, 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 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 general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. 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.

Additionally, pursuant to an 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. 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.

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 Current Quarter and Current Period, Chesapeake and its working interest partners accounted for approximately 91 percent and 93 percent, respectively, of the natural gas volumes on our gathering systems and 96 percent and 97 percent, respectively, 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.

16

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, 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 in order to maintain or increase throughput volumes on our gathering systems as a whole. Our success in connecting additional wells is impacted by successful drilling activity on the acreage dedicated to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, our ability to attract natural gas volumes currently gathered by our competitors and our ability to cost-effectively construct new infrastructure to connect new wells.

Operating Expenses

Our management seeks to maximize the profitability of our operations by minimizing operating expenses. These expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and measurements services among other items), compression expense, ad valorem and Texas Franchise taxes and other operating costs, some of which are independent of the volumes that flow 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.

Adjusted EBITDA and Distributable Cash Flow

We define Adjusted EBITDA as net income (loss) before income tax expense (benefit), interest expense, depreciation and amortization expense and certain other items management believes effect 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 generally accepted accounting principles (“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.

17

We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities, respectively. 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 their utility.

Items Impacting the Comparability of Our Financial Results

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

• At September 30, 2010, our assets constituted approximately 58 percent of the total assets of our Predecessor immediately prior to the formation of the joint venture between Chesapeake and GIP on September 30, 2009.

• 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 for historical periods presented in the unaudited condensed consolidated financial statements in Part I, Item I of this Form 10-Q were higher than those we anticipate we will experience in future periods.

• As a result of Chesapeake’s upstream joint venture with Total, Chesapeake has increased and we anticipate that Chesapeake will continue to increase its average operated rig count in our Barnett Shale acreage dedication during 2010 relative to comparative periods in 2009.

• Our Predecessor incurred impairments of property, plant and equipment of $90.2 million during the third quarter of 2009.

• We anticipate incurring approximately $2.0 million annually 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 NYSE; 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.

• 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.

• Our Predecessor’s historical consolidated financial statements include U.S. federal and state income tax expense. Due to our status as a partnership, we are not subject to U.S. federal income tax and certain state income taxes.

18

• We intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis). We have declared and paid a prorated distribution following the quarter ending September 30, 2010, covering the period from the closing of our initial public offering through September 30, 2010. Based on the terms of our cash distribution policy, we expect that we will distribute quarterly 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 that is not distributed to our unitholders and our general partner, borrowings under our amended 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.

Results of Operations – Three Months Ended September 30, 2010

Revenues. Our revenues are primarily attributable to the amount of throughput on its gathering systems and the rates charged for gathering such throughput. During the Current Quarter, revenues were $100.1 million compared to $101.2 million and $95.4 million during the three months ended June 30, 2010 and March 31, 2010, respectively. In the Current Quarter, throughput was 1,584 mmcf per day compared to 1,624 mmcf per day and 1,530 mmcf per day during the three month periods ended June 30, 2010 and March 31, 2010, respectively. Because throughput in the Barnett Shale during the Current Quarter was significantly below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the fourth quarter. The minimum volume commitment is measured annually and recognized in the fourth quarter of each year, as applicable. If the minimum volume commitment was recognized quarterly, revenue and net income would have increased $16.4 million in the Current Quarter. We connected 121 wells during the Current Quarter.

The table below reflects the Partnership’s revenues and throughput by region for the Current Quarter:

	Revenues		Throughput (bcf)
	(In thousands, except operational data)
Barnett Shale	$	75,411		94.7
Mid-Continent		24,649		51.0
	$	100,060		145.7

Operating Expenses. Operating expenses for the Barnett Shale and Mid-Continent regions were $0.23 per mcf for the Current Quarter compared to $0.22 per mcf during both of the three month periods ended June 30, 2010 and March 31, 2010. The table below reflects the Partnership’s total operating expenses and operating expenses per mcf of throughput by region for the Current Quarter:

	Operating Expenses		Expenses ($ per mcf)
	(In thousands, except per mcf data)
Barnett Shale	$	22,581	$	0.24
Mid-Continent		11,513		0.23
	$	34,094	$	0.23

Depreciation and Amortization Expense.Depreciation and amortization expense for the Current Quarter was $23.8 million compared to $23.4 and $22.0 million during the three months ended June 30, 2010 and March 31, 2010, respectively, and primarily related to gathering systems.

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $7.1 million compared to $7.4 million during the three months ended June 30, 2010, and were primarily attributable to completing the expansion of our general and administrative functions, specifically in preparation for the functions required by our status as a public company following the Offering.

19

Interest Expense. Interest expense for the Current Quarter was $0.7 million which was net of $0.4 million of capitalized interest. Interest expense is related to borrowings under our revolving credit facility and commitment fees on the unused portion of the Partnership’s credit facility.

Income Tax Expense. Income tax expense during the Current Quarter was $0.7 million and is attributable to margin taxes in the state of Texas. The Partnership 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 unaudited condensed consolidated financial statements.

Adjusted EBITDA and Distributable Cash Flow.We believe that the presentation of Adjusted EBITDA and distributable cash flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities, respectively. For definitions and additional discussion of these non-GAAP metrics, please seeHow We Evaluate Our Operations in this Part I, Item 2. Following are reconciliations of each of these non-GAAP metrics to its most directly comparable GAAP measure for the Current Quarter:

	Three Months Ended September 30, 2010
	($ in thousands)
Net Income	$	33,414
Interest expense		681
Income tax expense		699
Depreciation and amortization expense		23,785
(Gain) Loss on sale of assets		323
Adjusted EBITDA	$	58,902
Cash Provided By Operating Activities	$	69,711
Changes in assets and liabilities		(12,048	)
Maintenance capital expenditures		(17,500	)
Other non-cash items		(141	)
Distributable Cash Flow	$	40,022

Results of Operations – Nine Months Ended September 30, 2010

Revenues. During the Current Period, our throughput was 1,580 mmcf per day resulting in revenues of $296.7 million. Because throughput in the Barnett Shale during the Current Period was significantly below contractual minimum volume commitment levels, we expect to recognize additional revenue related to volume shortfall in the fourth quarter. The minimum volume commitment is measured annually and recognized in the fourth quarter of each year, as applicable. If the minimum volume commitment was recognized quarterly, revenue and net income would have increased $47.8 million in the Current Period. We connected 301 wells during the Current Period.

The table below reflects the Partnership’s revenues and throughput by region for the Current Period:

	Revenues		Throughput (bcf)
	(In thousands, except operational data)
Barnett Shale	$	222,951		279.2
Mid-Continent		73,734		152.0
	$	296,685		431.2

20

Operating Expenses. Operating expenses for the Barnett Shale and Mid-Continent regions were $0.23 per mcf for the Current Period. The table below reflects the Partnership’s total operating expenses and operating expenses per mcf of throughput by region for the Current Period:

	Operating Expenses		Expenses ($ per mcf)
	(In thousands, except per mcf data)
Barnett Shale	$	62,018	$	0.22
Mid-Continent		35,154		0.23
	$	97,172	$	0.23

Depreciation and Amortization Expense.Depreciation and amortization expense for the Current Period was $69.2 million and primarily related to gathering systems.

General and Administrative Expense. During the Current Period, general and administrative expenses were $21.2 million and were primarily attributable to the expansion of our senior management team and the ongoing expansion of general and administrative functions of the Partnership.

Interest Expense. Interest expense for the Current Period was $1.8 million which was net of $1.9 million of capitalized interest. Interest expense is related to borrowings under our revolving credit facility.

Income Tax Expense.Income tax expense during the Current Period was $1.8 million and is attributable to margin taxes in the state of Texas. The Partnership 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 unaudited condensed consolidated financial statements.

Adjusted EBITDA and Distributable Cash Flow.Following are reconciliations of each of these non-GAAP metrics to its most directly comparable GAAP measure for the Current Period:

	Nine Months Ended September 30, 2010
	($ in thousands)
Net Income	$	105,345
Interest expense		1,818
Income tax expense		1,772
Depreciation and amortization expense		69,177
(Gain) Loss on sale of assets		256
Adjusted EBITDA	$	178,368
Cash Provided By Operating Activities	$	267,120
Changes in assets and liabilities		(92,243	)
Maintenance capital expenditures		(52,500	)
Other non-cash items		(99	)
Distributable Cash Flow	$	122,278

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 as well as the availability of borrowings under our revolving credit facility and our access to the capital markets. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. SeeRisk Factorsin our prospectus dated July 28, 2010 and filed with the Securities and Exchange Commission (“SEC”) on July 30, 2010.

21

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 September 30, 2010, we had working capital of $49.4 million and $267.7 million, respectively. Working capital increased from December 31, 2009 to September 30, 2010 primarily as a result of proceeds from the Offering.

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

	Nine Months Ended September 30, 2010
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	267,120
Investing activities	$	(152,047	)
Financing activities	$	194,054

Operating Activities. Net cash provided by operating activities was $267.1 million for the Current Period. This amount was attributable to both cash flow from operations and changes in working capital. Cash flow from operations has increased as additional volumes have been brought onto our systems. Working capital is positive as a result of settlement of December 31, 2009 accounts receivable and accrued liabilities with Chesapeake in connection with the post-closing requirements of the purchase agreement relating to the joint venture transaction between Chesapeake and GIP.

Investing Activities. Net cash used in investing activities for the Current Period was primarily attributable to capital spending related to the expansion of gathering systems.

Financing Activities. Net cash provided by financing activities increased $194.1 million for the Current Period. This increase was primarily attributable to net proceeds of $475.0 million from the Offering offset by distributions during the period of $231.9 million and net payments on long-term borrowings of $44.1 million.

Sources of Liquidity

At September 30, 2010, our potential sources of liquidity included:

• cash on hand after the application of a portion of the net proceeds from the Offering to repay borrowings outstanding under our revolving credit facility;

• cash generated from operations;

• borrowings under our revolving credit facility.

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.

22

Credit Facility

In connection with the Offering, we further amended Successor’s revolving bank credit facility, which will now mature in June 2015. As amended, the credit facility provides up to $750 million of borrowing capacity and includes a sub-limit of $25 million for same-day swing line advances and a sub-limit of $50 million for letters of credit. In addition, the credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the credit facility. Borrowings under the credit facility are secured by all of the assets of the Partnership and its subsidiaries, and loans thereunder (other than swing line loans) bear interest at our 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 is subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent consolidated leverage ratio. The unused portion of the credit facility is subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. At September 30, 2010, there were no outstanding borrowings under such credit facility and at December 31, 2009, there were $44.1 million of outstanding borrowings under such credit facility.

Our amended credit facility agreement requires maintenance of an indebtedness to EBITDA ratio (as defined in the amended credit facility agreement) of not more than 4.50 to 1, and an EBITDA to interest expense ratio (as defined in the amended credit facility agreement) of not less than 3.00 to 1. We were in compliance with all covenants under the agreement at September 30, 2010.

Additionally, the credit facility contains various covenants and restrictive provisions which, among other things, limits the ability of the Partnership and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. If the Partnership fails 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 credit facility could be declared immediately due and payable. The credit facility agreement also has cross default provisions that apply to any other indebtedness the Partnership has with an outstanding principal amount in excess of $15 million.

Capital Requirements. Our business is capital-intensive, requiring significant investment to grown our business as well as to maintain and improve existing assets. We categorize capital expenditures as either:

• maintenance capital expenditures, which include those expenditures required to maintain our long-term operating capacity and/or operating income and service capability of our assets, including the replacement of system components and equipment that have suffered significant wear and tear, become obsolete or approached the end of their useful lives, those expenditures necessary to remain in compliance with regulatory legal requirements or those expenditures necessary to complete additional well connections to maintain existing system volumes and related cash flows; or

• expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, 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.

For the Current Period, expansion capital expenditures totaled $104.0 million and maintenance capital expenditures totaled $52.5 million. Our 2010 year-to-date spending and budgeted capital expenditures for the remainder of 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.

23

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 most of the cash generated from operations to our unitholders and our general partner, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations that is not distributed to our unitholders and general partner, borrowings under our revolving credit facility and future issuances of equity and debt securities.

Distributions We intend to pay a minimum quarterly distribution of $0.3375 per unit per quarter, which we expect to equate to approximately $47.6 million per quarter, or approximately $190.3 million per year, based on the number of common, subordinated and general partner units outstanding immediately after completion of the Offering. We do not have a legal obligation to pay this distribution.

On October 26, 2010, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.2165 per unit together with the corresponding distribution to the general partner. This amount represents a minimum quarterly distribution prorated for the 59-day period beginning on August 3, 2010 and ending on September 30, 2010. The cash distribution was paid on November 12, 2010 to unitholders of record on November 5, 2010 and to the general partner.

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 which impact 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.

We consider depreciation and evaluation of long-lived assets for impairment to be critical policies and estimates. These policies and estimates are summarized in Management’s Discussion and Analysis of Financial Condition and Results of Operations in our prospectus dated July 28, 2010 and filed with the SEC on July 30, 2010.

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

• dependence on Chesapeake and Total for a substantial majority of our revenues;

• the impact on our growth strategy and ability to increase cash distributions if Chesapeake and Total do not increase the volume of natural gas they provide to our gathering systems;

• the termination of our gas gathering agreements with Chesapeake or Total;

• our potential inability to pay the minimum quarterly distribution to our unitholders;

• the limitations that Chesapeake’s and our own level of indebtedness may have on our financial flexibility;

• our ability to obtain new sources of natural gas, which is dependent on factors largely beyond our control;

24

• the availability of capital resources to fund capital expenditures and other contractual obligations, and our ability to access those resources through the debt or equity capital markets;

• competitive conditions;

• the unavailability of third-party pipelines interconnected to our gathering systems or the potential that the volumes we gather do not meet the quality requirement of such pipelines;

• new asset construction may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks;

• our exposure to direct commodity price risk may increase in the future;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• hazards and operational risks that may not be fully covered by insurance;

• our dependence on Chesapeake for substantially all of our compression capacity;

• our lack of industry and geographic diversification; and

• legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by FERC and liability under federal and state environmental laws and regulations.

Other factors that could cause our actual results to differ from our projected results are described in (i) Part II, “Item 1A. Risk Factors” and elsewhere in this report, (ii) our prospectus dated July 28, 2010 and filed with the SEC on July 30, 2010, (iii) our reports and registration statements filed from time to time with the SEC and (iv) other announcements we make from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

25

ITEM 3. 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, is 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.

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 flows 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 and Total 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 and Total, 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 the cost 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.

26

ITEM 4. Controls and Procedures

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, the principal executive officer and principal financial officer of our general partner have concluded that our disclosure controls and procedures were effective as of September 30, 2010 at the reasonable assurance level.

There was no change in our internal control over financial reporting occurred during the quarter ended September 30, 2010, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

27

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings

We are not 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. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position.

ITEM 1A. Risk Factors

Our business has many risks. Factors that could materially adversely affect our business, financial condition, operating results or liquidity and the trading price of our common units are described under the heading “Risk Factors” in our prospectus dated July 28, 2010 and filed with the SEC on July 30, 2010. This information should be considered carefully, together with other information in this report and other reports and materials we file with the SEC.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

ITEM 3. Defaults Upon Senior Securities

Not applicable.

ITEM 4. (Removed and Reserved)

ITEM 5. Other Information

Not applicable.

28

ITEM 6. Exhibits

The following exhibits are filed as a part of this report:

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010
3.2	First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010.		8-K		001-34831		3.1		08/05/2010
3.3	Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		3.2		08/05/2010
10.1	Underwriting Agreement, dated July 28, 2010, by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Ventures, L.L.C., Chesapeake MLP Operating, L.L.C and the Underwriters named therein.		8-K		001-34831		1.1		07/30/2010
10.2	Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010.		8-K		001-34831		10.1		07/30/2010
10.3	Omnibus Agreement by and among Chesapeake Midstream Holding, L.L.C. and Chesapeake Midstream Ventures, L.L.C., dated August 3, 2010.		8-K		001-34831		10.1		08/05/2010
10.4	Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		10.2		08/05/2010
10.5	Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		10.3		08/05/2010

29

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.6

Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.

8-K

001-34831

10.4

08/05/2010

10.7

Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.

8-K

001-34831

10.5

08/05/2010

10.8

Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010.

8-K

001-34831

10.6

08/05/2010

10.9

Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, The Royal Bank of Scotland plc, as Syndication Agent, Bank of Montreal, Compass Bank and The Bank of Nova Scotia, as Co-Documentation Agents and the other Lenders party thereto, dated as of August 2, 2010.

8-K

001-34831

10.7

08/05/2010

10.10

Chesapeake Midstream Long-Term Incentive Plan.

S-1

333-164905

10.18

07/20/2010

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

30

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CHESAPEAKE MIDSTREAM PARTNERS, L.P.
Date: November 12, 2010	By:	/s/ J. MIKE STICE
		J. Mike Stice Chief Executive Officer
Date: November 12, 2010	By:	/s/ DAVID C. SHIELS
		David C. Shiels Chief Financial Officer

31

INDEX TO EXHIBITS

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form		SEC File Number		Exhibit		Filing Date		Filed Herewith	Furnished Herewith
3.1	Certificate of Limited Partnership of Chesapeake Midstream Partners, L.P.		S-1		333-164905		3.1		02/16/2010
3.2	First Amended and Restated Agreement of Limited Partnership of Chesapeake Midstream Partners, L.P. dated August 3, 2010.		8-K		001-34831		3.1		08/05/2010
3.3	Second Amended and Restated Limited Liability Company Agreement of Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		3.2		08/05/2010
10.1	Underwriting Agreement, dated July 28, 2010, by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Ventures, L.L.C., Chesapeake MLP Operating, L.L.C and the Underwriters named therein.		8-K		001-34831		1.1		07/30/2010
10.2	Contribution, Conveyance and Assumption Agreement by and among Chesapeake Midstream Partners, L.P., Chesapeake Midstream GP, L.L.C., Chesapeake Midstream Holdings, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P., Chesapeake Midstream Ventures, L.L.C. and Chesapeake MLP Operating, L.L.C., dated as of July 28, 2010.		8-K		001-34831		10.1		07/30/2010
10.3	Omnibus Agreement by and among Chesapeake Midstream Holding, L.L.C. and Chesapeake Midstream Ventures, L.L.C., dated August 3, 2010.		8-K		001-34831		10.1		08/05/2010
10.4	Amended and Restated Services Agreement by and among Chesapeake Midstream Management, L.L.C., Chesapeake Operating, Inc., Chesapeake Midstream GP, L.L.C, Chesapeake Midstream Partners, L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		10.2		08/05/2010
10.5	Amended and Restated Employee Transfer Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.		8-K		001-34831		10.3		08/05/2010

32

Incorporated by Reference

Exhibit Number

Exhibit Description

Form

SEC File Number

Exhibit

Filing Date

Filed Herewith

Furnished Herewith

10.6

Amended and Restated Employee Secondment Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream Management, L.L.C., Chesapeake Midstream GP, L.L.C., Chesapeake Operating, Inc. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.

8-K

001-34831

10.4

08/05/2010

10.7

Amended and Restated Shared Services Agreement by and among Chesapeake Energy Corporation, Chesapeake Midstream GP, L.L.C., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake MLP Operating, L.L.C., dated August 3, 2010.

8-K

001-34831

10.5

08/05/2010

10.8

Registration Rights Agreement by and among Chesapeake Midstream Partners, L.P., GIP-A Holding (CHK), L.P., GIP-B Holding (CHK), L.P., GIP-C Holding (CHK), L.P. and Chesapeake Midstream Holdings, L.L.C., dated August 3, 2010.

8-K

001-34831

10.6

08/05/2010

10.9

Credit Agreement among Chesapeake MLP Operating, L.L.C., as the Borrower, Chesapeake Midstream Partners, L.P., as the Parent, Wells Fargo Bank, National Association, as Administrative Agent, The Royal Bank of Scotland plc, as Syndication Agent, Bank of Montreal, Compass Bank and The Bank of Nova Scotia, as Co-Documentation Agents and the other Lenders party thereto, dated as of August 2, 2010.

8-K

001-34831

10.7

08/05/2010

10.10

Chesapeake Midstream Long-Term Incentive Plan.

S-1

333-164905

10.18

07/20/2010

31.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

31.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

X

32.1

J. Mike Stice, Chief Executive Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

32.2

David C. Shiels, Chief Financial Officer, Certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

X

33