Williams Partners 10Q 2011 Q1 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 March 31, 2011

[ ]	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.)

900 NW 63^rd Street
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 May 9, 2011, the registrant had 69,085,038 common units outstanding.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2011


PART I.
Financial Information
		Page
Item 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010		1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010		2
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010		3
	Condensed Consolidated Statement of Changes in Partners’ Capital for the Three Months Ended March 31, 2011		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		25
Item 4.	Controls and Procedures		26

PART II.
Other Information

Item 1.	Legal Proceedings		27
Item 1A.	Risk Factors		27
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		27
Item 3.	Defaults Upon Senior Securities		27
Item 4.	(Removed and Reserved)		27
Item 5.	Other Information		27
Item 6.	Exhibits		28

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2011				December 31, 2010
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents		$	18			$	17,816
Accounts receivable, including $40,638 and $88,009 from related parties at March 31, 2011 and December 31, 2010, respectively			56,818				107,095
Other current assets			5,575				6,576

Total current assets			62,411				131,487

Property, plant and equipment:
Gathering systems			2,653,523				2,544,053
Other fixed assets			43,882				41,125
Less: Accumulated depreciation			(386,056	)			(358,269	)

Total property, plant and equipment, net			2,311,349				2,226,909

Intangible contracts			167,046				172,481
Deferred loan costs, net			14,221				15,039

Total assets		$	2,555,027			$	2,545,916


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable		$	57,080			$	39,619
Accrued liabilities, including $46,725 and $42,674 from related parties at March 31, 2011 and December 31, 2010, respectively			59,720				58,372

Total current liabilities			116,800				97,991

Long-term liabilities:
Revolving bank credit facility			249,200				249,100
Other liabilities			4,304				4,257


Total long-term liabilities			253,504				253,357


Commitments and contingencies (Note 9)
Partners’ Capital:
Common units (69,084,576 and 69,083,265 issued and outstanding at March 31, 2011 and December 31, 2010, respectively)			1,280,279				1,285,619
Subordinated units (69,076,122 issued and outstanding at March 31, 2011 and December 31, 2010)			868,971				873,304
General partner units (2,819,606 and 2,819,434 issued and outstanding at March 31, 2011 and December 31, 2010, respectively)			35,473				35,645

Total partners’ capital			2,184,723				2,194,568

Total liabilities and partners’ capital		$	2,555,027			$	2,545,916

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

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
	($ in thousands, except per unit data)
Revenues, including revenue from affiliates (Note 7)	$	123,529		$	95,386

Operating Expenses:
Operating expenses, including expenses from affiliates (Note 8)		42,561			30,693
Depreciation and amortization expense		31,758			21,950
General and administrative expense, including expenses from affiliates (Note 8)		8,946			6,736
Gain on sale of assets		(60	)		(30	)

Total operating expenses		83,205			59,349


Operating income		40,324			36,037

Other Income (Expense):
Interest expense (Note 5)		(620	)		(611	)
Other income		42			2

Income before income tax expense		39,746			35,428
Income tax expense		970			514

Net income	$	38,776		$	34,914

Limited partner interest in net income
Net income	$	38,776			N/A
Less general partner interest in net income		(776	)		N/A

Limited partner interest in net income	$	38,000			N/A


Net income per common unit – basic and diluted	$	0.27			N/A
Net income per subordinated unit – basic and diluted	$	0.27			N/A

Weighted average limited partner units outstanding used for net income per unit calculation – basic and diluted (in thousands)
Common units		69,219			N/A
Subordinated units		69,076			N/A

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

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
	($ in thousands)
Cash flows from operating activities:
Net income	$	38,776		$	34,914
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		31,758			21,950
Gain on sale of assets		(60	)		(30	)
Other non-cash items		244			(988	)
Changes in assets and liabilities:
Decrease in accounts receivable		50,277			120,362
Decrease (increase) in other assets		1,001			(226	)
Increase in accounts payable		13,924			3,655
Increase (decrease) in accrued liabilities		1,349			(61,312	)

Net cash provided by operating activities		137,269			118,325


Cash flows from investing activities:
Additions to property, plant and equipment		(106,521	)		(39,451	)
Proceeds from sale of assets		211			53

Net cash used in investing activities		(106,310	)		(39,398	)


Cash flows from financing activities:

Proceeds from long-term debt borrowings		134,200			84,400
Payments on long-term debt borrowings		(134,100	)		(128,500	)
Distributions to unit holders		(47,581	)		—
Initial public offering costs		(1,280	)		—
Distributions to partners		—			(19,500	)
Contribution from CMD		—			177
Other		4			—

Net cash used in financing activities		(48,757	)		(63,423	)

Net increase (decrease) in cash and cash equivalents		(17,798	)		15,504
Cash and cash equivalents, beginning of period		17,816			3

Cash and cash equivalents, end of period	$	18		$	15,507


Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	3,536		$	2,799
Changes in other liabilities related to asset retirement obligations	$	—		$	53
Contributions of property, plant and equipment to (from) Chesapeake	$	—		$	9,162

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

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS’ CAPITAL

(Unaudited)

		Subordinated			Subordinated			Subordinated			Subordinated
	Limited Partners						General Partner			Total
	Common			Subordinated			General Partner			Total
Balance at December 31, 2010	$	1,285,619		$	873,304		$	35,645		$	2,194,568
Net income		19,020			18,980			776			38,776
Distribution to unitholders		(23,316	)		(23,313	)		(952	)		(47,581	)
Initial public offering costs		(1,280	)		—			—			(1,280	)
Non-cash equity based compensation		236			—			—			236
Other Adjustments		—			—			4			4

Balance at March 31, 2011	$	1,280,279		$	868,971		$	35,473		$	2,184,723

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

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 under long-term, fixed-fee contracts, and other third-party producers under fixed-fee contracts.

Chesapeake Midstream Development, L.P. (“CMD”) is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating 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 percent ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a two percent ownership interest. CMM is a wholly owned subsidiary of CEMI.

On September 30, 2009, CMD 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, CMD 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 percent interest in the newly formed joint venture.

The assets contributed to the joint venture and ultimately the Partnership were substantially all of CMD’s midstream assets in the Barnett Shale and certain of its midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. Subsidiaries of CMD continue to operate midstream assets outside of the Partnership. These include natural gas gathering assets primarily in the 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 (“IPO”) 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”. Upon completion of the IPO, Chesapeake and GIP conveyed to the Partnership a 100 percent membership interest in Successor (renamed as “Chesapeake MLP Operating, L.L.C.”).

At March 31, 2011, the Partnership had outstanding 69,084,576 common units, 69,076,122 subordinated units, a two percent 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 the public represented 17.7 percent of all outstanding limited partner interests, and Chesapeake and GIP held 42.3 percent and 40.0 percent, respectively, of all outstanding limited partner interests. The limited partners, collectively, hold a 98.0 percent limited partner interest in the Partnership and the general partner, which is indirectly owned and controlled by Chesapeake and GIP, holds a two percent general partner interest in the Partnership.

On December 21, 2010, the Partnership completed the Springridge acquisition for $500.0 million in cash that was funded with a draw on the Partnership’s revolving credit facility of approximately $234.0 million plus approximately $266.0 million of cash on hand. The Springridge gathering system consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, the Partnership entered into a 10 year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication and annual fee redetermination. The agreement also includes an annual minimum volume commitment through December 31, 2013.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

2.	Basis of Presentation

Unless the context otherwise requires, references to our historical financial results, “our assets,” “our systems” and similar descriptions of the Partnership’s business and operations relate to the financial results, assets and systems of (i) Successor for periods prior to the closing of the IPO and (ii) the Partnership for periods after the closing of the IPO and include the financial results, assets and systems relating to the Springridge acquisition for periods after December 21, 2010.

The accompanying financial statements and related notes present the condensed consolidated balance sheets of the Partnership as of March 31, 2011 and December 31, 2010. They also include the condensed consolidated statements of operations and the condensed consolidated statements of cash flows for the Partnership for the three month periods ended March 31, 2011 and 2010, and changes in partners’ capital of the Partnership for the three month period ended March 31, 2011.

The accompanying 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 annual report on Form 10-K for the year ended December 31, 2010.

The results of operations for the three month period ended March 31, 2011, are not indicative of results that may be expected for the full fiscal year.

3.	Partnership Capital 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. During the three months ended March 31, 2011, the Partnership paid cash distributions to its unitholders of approximately $47.6 million, representing a $0.3375 per-unit distribution for the quarter ended December 31, 2010. See also Note 10 — Subsequent Events concerning distributions declared on April 26, 2011.

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.

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.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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. 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 or greater than the minimum quarterly distribution.

The Subordination Period will lapse at such time when the Partnership has earned and 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 earned and paid at least 150 percent of the minimum quarterly distribution on each outstanding common unit, subordinated unit and general partner unit and the related distribution on the incentive distribution rights in a four-quarter period, the Subordination Period will terminate.

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.

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.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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):


	Three Months Ended March 31, 2011
Net income attributable to Chesapeake Midstream Partners, L.P.	$	38,776
Less general partner interest in net income		(776	)

Limited partner interest in net income	$	38,000


Net income allocable to common units	$	19,020
Net income allocable to subordinated units		18,980

Limited partner interest in net income	$	38,000


Net income per limited partner unit – basic and diluted
Common units	$	0.27
Subordinated units		0.27

Total	$	0.27

Weighted average limited partner units outstanding used for basic and diluted net income per unit calculation
Common units		69,219,183
Subordinated units		69,076,122

Total		138,295,305

5.	Long-Term Debt

Revolving Credit Facility

The Partnership maintains a revolving bank credit facility which matures in July 2015. 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 percent, and the one-month LIBOR plus 1.00 percent, all of which is subject to a margin that varies from 1.75 percent to 2.25 percent per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varies from 2.75 percent to 3.25 percent 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 percent per annum according to the most recent consolidated leverage ratio. There were $249.2 million and $249.1 million of outstanding borrowings under the credit facility at March 31, 2011 and December 31, 2010, respectively.

The Partnership’s credit facility agreement requires maintenance of a consolidated leverage ratio (as defined in the amended credit facility agreement), and an EBITDA to interest expense ratio (as defined in the amended credit facility agreement). The Partnership was in compliance with all covenants under the agreement at March 31, 2011.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Additionally, the credit facility contains various covenants and restrictive provisions which, among other things, limit 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 March 31, 2011, for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

Capitalized Interest

For the three month periods ended March 31, 2011 and March 31, 2010, interest expense was net of capitalized interest of $2.0 million and $0.3 million, respectively.

See also Note 10 – Subsequent Events concerning the offering of Senior Notes due 2021.

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 equity-based compensation programs, which consist of restricted stock or restricted units issued to employees.

The fair value of the awards issued is determined based on the fair market value of the shares or units on the date of grant. For grants of Partnership units, expense is based on grant date fair value amortized evenly over the vesting period. However, expense for Chesapeake stock grants is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period. The vesting period for both types of awards 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 are reflected as operating expenses. Included in operating expenses is equity-based compensation of $1.1 million and $0.6 million for the Partnership during the three month periods ended March 31, 2011 and March 31, 2010, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to the Partnership through an overhead allocation and are reflected as general and administrative expenses.

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.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The following table summarizes LTIP award activity for the three months ended March 31, 2011:


	Units			Value per Unit
Restricted units outstanding at beginning of period		—		$	—

Granted		143,453			28.51
Vested		(1,311	)		28.62
Forfeited		(2,455	)		28.62


Restricted units outstanding at end of period		139,687		$	28.51

7.	Major Customers and Concentration of Credit Risk

CEMI accounted for $103.3 million and $82.5 million of the Partnership’s revenues for the three month periods ended March 31, 2011 and March 31, 2010, respectively. Total accounted for $16.4 million and $10.3 million of the Partnership’s revenues for the three month periods ended March 31, 2011 and March 31, 2010, respectively.

Financial instruments that potentially subject the Partnership to concentrations of credit risk consist principally of cash and cash equivalents and trade receivables. On March 31, 2011 and December 31, 2010, respectively, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.

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 primarily from Chesapeake, which includes volumes attributable to third-party interest owners that participate in Chesapeake’s operated wells.

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 condensed consolidated financial statements for the Partnership 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. The Partnership is charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs 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 $0.03025/mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. General and administrative charges were $5.7 million and $3.9 million for the three month periods ended March 31, 2011 and March 31, 2010, respectively, for the Partnership.

Chesapeake and its affiliates also provide compression services. The Partnership is charged for compressor rentals based on a long-term compressor rental agreement with MidCon Compression, LLC, (“MidCon”) a wholly owned indirect subsidiary of Chesapeake. For the three month periods ended March 31, 2011 and March 31, 2010, compressor rental charges from affiliates were $14.2 million and $11.6 million, respectively. These charges are included in operating expenses in the accompanying condensed consolidated statements of operations.

See also Note 7 — Major Customers and Concentration of Credit Risk concerning revenues attributable to CEMI, an affiliate of the Partnership.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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.

The Partnership 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 information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to the estimate of the likely exposure. There was not an accrual for legal contingencies as of March 31, 2011 or December 31, 2010.

10.

Subsequent Events

Distribution

On April 26, 2011, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.35 per unit together with the corresponding distribution to the general partner. The cash distribution was paid on May 13, 2011, to unitholders of record at the close of business on May 6, 2011, and to the general partner.

Notes Offering

On April 19, 2011, the Partnership and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $350 million of 5.875 percent per annum senior notes due 2021. The Partnership used a portion of the net proceeds of approximately $342 million to repay borrowings outstanding under its revolving credit facility and intends to use the balance for general Partnership purposes.

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

Unless the context otherwise requires, references in this report to the “Partnership,” “we,” “our,” “us” or like terms, when used in a historical context, refer to the financial results of Chesapeake Midstream Partners, L.L.C. from its inception on September 30, 2009 through the closing date of our initial public offering (“IPO”) on August 3, 2010, and to Chesapeake Midstream Partners, L.P. and its subsidiaries thereafter. “CMD” refers to Chesapeake Midstream Development, L.P. which held substantially all of our assets as well as other midstream assets prior to September 30, 2009. “Chesapeake” refers to Chesapeake Energy Corporation (NYSE: CHK) and “GIP” refers to 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. “Total”, when discussing the upstream joint venture with Chesapeake, refers to Total E&P USA, Inc., a wholly owned subsidiary of Total S.A. (NYSE: TOT, FP: FP), and when discussing our gas gathering agreement and related matters, refers to Total E&P USA, Inc. and Total Gas & Power North America, Inc., a wholly owned subsidiary of Total S.A.

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 months ended March 31, 2011 (the “Current Quarter”) and March 31, 2010:


	Three Months Ended March 31, 2011			Three Months Ended March 31, 2010
	(In thousands, except operational data)
Revenues⁽¹⁾	$	123,529		$	95,386

Operating expenses		42,561			30,693
Depreciation and amortization expense		31,758			21,950
General and administrative expense		8,946			6,736
Gain on sale of assets		(60	)		(30	)

Total operating expenses		83,205			59,349

Operating income		40,324			36,037
Interest expense		(620	)		(611	)
Other income		42			2

Income before income tax expense		39,746			35,428
Income tax expense		970			514

Net income	$	38,776		$	34,914

Key Performance Metrics:
Adjusted EBITDA⁽²⁾	$	72,064		$	57,959
Distributable cash flow⁽²⁾	$	51,974		$	39,334
Operational Data:
Wells connected during period		155			84
Wells connected at end of period		4,510			3,956
Throughput, bcf per day		2.008			1.530
Miles of pipe at end of period		3,386			2,800
Gas compression (horsepower) at end of period		248,314			218,519

(1)

In the event either Chesapeake or Total does not meet its minimum volume commitment to the Partnership in the Barnett Shale region or Chesapeake does not meet its minimum volume commitment in the Haynesville Shale region under the applicable gas gathering agreement for specified annual periods, Chesapeake or Total is obligated to pay the Partnership a fee equal to the applicable fee for each mcf by which the applicable party’s minimum volume commitment for the year exceeds the actual volumes gathered on the Partnership’s systems. 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 and reconciled to their most directly comparable financial measures calculated and presented in accordance with GAAP below under the captionHow We Evaluate Our Operations within this Part I, Item 2.

We are a growth-oriented publicly-traded Delaware limited partnership formed by Chesapeake Energy Corporation (“Chesapeake”) and Global Infrastructure Partners (“GIP”) to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We currently operate in Texas, Louisiana, Oklahoma, Kansas and Arkansas. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers under long-term, fixed-fee contracts, and other third-party producers under fixed-fee contracts.

Our gathering systems operate in our Barnett Shale region in north central Texas, our Haynesville Shale region in northwest Louisiana 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 1,925 wells in the core of the prolific Barnett Shale. Our Springridge gathering system services approximately 183 wells in one of the core areas of the Haynesville 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. In total, our systems consist of approximately 3,390 miles of gathering pipelines, servicing approximately 4,510 natural gas wells. For the Current Quarter our assets gathered approximately 2.0 billion cubic feet (“Bcf”) of natural gas per day.

We generated approximately 62 percent of our revenues from our gathering systems in our Barnett Shale region, approximately 17 percent of our revenues from our gathering systems in our Haynesville Shale region and approximately 21 percent of our revenues from our gathering systems in our Mid-Continent region for the Current Quarter.

Acquisition

Springridge Acquisition.On December 21, 2010, we acquired the Springridge gathering system in the Haynesville Shale Region and related facilities from Chesapeake Midstream Development, L.P., a wholly owned subsidiary of Chesapeake, for $500 million. The Springridge gathering system consists of 226 miles of gathering pipeline primarily located in Caddo and De Soto Parishes, Louisiana. In connection with the acquisition, we entered into a 10 year, 100 percent fixed-fee gas gathering agreement with Chesapeake which includes a significant acreage dedication, annual fee redetermination, annual fee escalation and a three year minimum volume commitment.

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, (ii) a 20 year gas gathering agreement with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total in January 2010, and (iii) a 10 year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of the acquisition of the Springridge gas gathering system in December 2010.

Future revenues under our gas gathering agreements will be derived pursuant to terms that will differ between our three operating regions. The following outlines the key economic provisions of our gas gathering agreements by region.

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

•

Gathering, Treating and Compression Services. We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per mcf for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems 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 of 2.0 percent 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 percent of the aggregate minimum volume commitment will be attributed to Chesapeake, and approximately 25 percent will be attributed to Total. The minimum volume commitments increase, on average, approximately three percent 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 percent 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.

•

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. During the minimum volume commitment period, if we fail to complete a connection in the acreage dedication by the required date, Chesapeake and Total, as their sole remedy for such delayed connection, are entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection

•

Fuel, Lost and Unaccounted For Gas. We have agreed with Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s volumes. These caps do not apply to certain of our gathering systems due to their historic performance relative to the caps. These systems will be reviewed annually to determine whether changes have occurred that would make them suitable for inclusion. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will subject us to direct commodity price risk.

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

•

Gathering, Treating and Compression Services.We gather, treat and compress natural gas in exchange for fees per mcf for natural gas gathered and per mcf for natural gas compressed, which we refer to as the Haynesville fees. The Haynesville fees for this system are subject to an annual specified rate escalation at the beginning of each year.

•

Minimum Volume Commitments. Pursuant to our gas gathering agreement, Chesapeake has agreed to minimum volume commitments for each year through December 31, 2013. In the event Chesapeake does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period during the minimum volume commitment period, Chesapeake will be obligated to pay us a fee equal to the Haynesville fee for each mcf by which the minimum volume commitment for the year exceeds the actual volumes gathered on our system attributable to Chesapeake’s production. To the extent natural gas gathered on our system from Chesapeake during any annual period exceeds Chesapeake’s minimum volume commitment for the period, Chesapeake will be obligated to pay us the Haynesville fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the year 2013, 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.

•

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 within the Haynesville Shale region acreage dedication.

•

Fee Redetermination. The Haynesville fees are subject to a redetermination mechanism. The first redetermination period will extend from December 1, 2010 through December 31, 2012, and subsequent redetermination periods will be the calendar years 2013 through 2020. We will determine an adjustment to fees for the gathering system 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 December 31, 2020, referred to as the redetermination period, made as of November 30, 2010. The annual upward or downward fee adjustment for the Haynesville Shale region is capped at 15 percent of the then current fees at the time of redetermination.

•

Well Connection Requirement. We have certain connection obligations for new operated drilling pads and operated wells of Chesapeake in the acreage dedications. Chesapeake is required to provide us notice of new drilling pads and wells operated by Chesapeake in the acreage dedications. Subject to certain conditions specified in the gas gathering agreement, we are generally required to connect new operated drilling pads in the acreage dedication by the later of 30 days after the date the wells commence production or six months after the date of the connection notice. During the minimum volume period, if we fail to complete a connection in the Haynesville Shale acreage dedication by the required date, Chesapeake, as its sole remedy for such delayed connection, is entitled to a delay in the minimum volume obligations for gas volumes that would have been produced from the delayed connection. After the minimum volume period, we are subject to a daily penalty for such delayed connections, up to a specified cap per delayed connection. Chesapeake also is required to notify us of its wells drilled in the acreage dedications that are operated by other parties and we have the option, but not the obligation, to connect non-operated wells to our gathering system. If we decline to make a connection to a non-operated well, Chesapeake has certain rights to have the well released from the dedication under the gas gathering agreement.

•

Fuel, Lost and Unaccounted For Gas. We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas in the Haynesville Shale system with respect to Chesapeake’s volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed-upon cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, or lost or unaccounted for, in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation may 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 percent rate escalation at the beginning of each year.

•

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 percent 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.

•

We believe the recent trend of producers moving drilling rigs from dry gas regions to liquids rich plays such as the Mid-Continent may present an opportunity for us to enter the market of gathering and transporting oil as we believe those services fit well with our current business model.

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 Haynesville Shale region and 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 or enter into a new gas gathering agreement with us on substantially similar terms to our existing gas gathering agreement with Chesapeake or Total.

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 in our Barnett Shale and Mid-Continent regions, (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 reimburse Chesapeake for such general and administrative services in any given month subject to a cap equal to $0.03025 per mcf multiplied by the volume (measured in mcf) of natural gas that we gather, treat or compress. The fee is calculated as the lesser of $0.03025/mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. The $0.03025 per mcf cap is subject to an annual upward adjustment on October 1 of each year equal to 50 percent 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.

Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake are 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, subject to specified exceptions and limitations, reimburses 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 are required to maintain certain compensation standards for seconded employees to whom we make offers for hire.

How We Evaluate Our Operations

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) revenues, (iii) operating expenses, (iv) Adjusted EBITDA and (v) distributable cash flow.

Throughput Volumes

Although Chesapeake’s and Total’s respective minimum volume commitments generally provide us with protection in the event that throughput volumes from Chesapeake or Total in the Barnett Shale region and Chesapeake in the Haynesville 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 our Barnett Shale, Haynesville 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.

Revenues

Our revenues 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 and Haynesville Shale volumes, our results will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total. We contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the three months ended March 31, 2011, Chesapeake accounted for approximately 84.3 percent of the natural gas volumes on our gathering systems and 83.7 percent of our revenues.

Our revenues are also impacted by other aspects of our contractual agreements, including rate redetermination, and our management constantly evaluates capital spending and its impact on future revenue generation.

Operating Expenses

Our management seeks to maximize the profitability of our operations by minimizing operating expenses while never compromising environmental protection and employee safety. Operating expenses are comprised primarily of field operating costs (which include labor, treating and chemicals, and measurement services, among other items), compression expense, ad valorem 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 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 affect the comparability of operating results.

We define distributable cash flow as Adjusted EBITDA, plus interest income, less 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.

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.

The following table presents a reconciliation of the non-GAAP financial measure of Adjusted EBITDA to the GAAP financial measure of net income and a reconciliation of the non-GAAP financial measure of distributable cash flow to the GAAP financial measure cash provided by operating activities:


	Three Months Ended March 31,
	2011			2010
	($ in thousands)
Net Income	$	38,776		$	34,914
Interest expense		620			611
Income tax expense		970			514
Depreciation and amortization expense		31,758			21,950
(Gain) Loss on sale of assets		(60	)		(30	)

Adjusted EBITDA	$	72,064		$	57,959


Cash Provided By Operating Activities	$	137,269		$	118,325
Changes in assets and liabilities		(66,551	)		(62,479	)
Maintenance capital expenditures		(18,500	)		(17,500	)
Other non-cash items		(244	)		988

Distributable Cash Flow	$	51,974		$	39,334

Results of Operations

Revenues. Our revenues are primarily attributable to the amount of throughput on our gathering systems and the rates charged for gathering such throughput. For the Current Quarter, revenues were $123.5 million compared to $95.4 million during the three months ended March 31, 2010, primarily as a result of volumes added through the Springridge gathering system acquisition. Revenue was positively impacted by Mid-Continent redetermination of gathering rates that occurred January 1, 2011 and rate escalation of two percent in the Barnett Shale and two and a half percent in the Mid-Continent region. We also benefitted from added compression revenue during the Current Quarter. For the three months ended March 31, 2011, throughput was 2.008 Bcf per day compared to 1.530 Bcf per day for the three months ended March 31, 2010. 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 of 2011. The minimum volume commitment is measured annually and the associated revenue recognized in the fourth quarter of each year. If our estimate of minimum volume commitment for the full year of 2011 was recognized quarterly, revenue and net income would have increased $5.3 million in the Current Quarter. We connected 155 wells during the Current Quarter compared to 84 new wells in the first quarter of 2010. The following table reflects the Partnership’s revenues and throughput by region for the three months ended March 31, 2011 and 2010:


	Three Months Ended March 31,
	2011		2010		% Change⁽¹⁾
	(In thousands, except percentages and throughput data)
Revenue:
Barnett Shale	$	76,027	$	71,600		6.2	%
Haynesville Shale		20,916		—		N.M.
Mid-Continent		26,586		23,786		11.8	%

	$	123,529	$	95,386		29.5	%


Throughput (bcf):
Barnett Shale		87.2		88.1		(1.0	)%
Haynesville Shale		44.5		—		N.M.
Mid-Continent		49.0		49.6		(1.2	)%

		180.7		137.7		31.2	%

⁽¹⁾	N.M. - not meaningful

Operating Expenses. For the Current Quarter, operating expenses were $0.24 per mcf compared to $0.22 per mcf during the three months ended March 31, 2010. This increase was due to additional compression expense that has increased the Partnership’s overall throughput capacity and additional field personnel resulting from Partnership growth and other personnel related costs. The following table reflects the Partnership’s operating expenses and operating expenses per mcf of throughput by region for the three months ended March 31, 2011 and March 31, 2010:


	Three Months Ended March 31,
	2011		2010		% Change⁽¹⁾
	(In thousands, except percentages and per mcf data)
Operating Expenses:
Barnett Shale	$	23,685	$	18,965		24.9	%
Haynesville Shale		5,512		—		N.M.
Mid-Continent		13,364		11,728		13.9	%

	$	42,561	$	30,693		38.7	%


Expenses ($ per mcf):
Barnett Shale	$	0.27	$	0.22		22.7	%
Haynesville Shale		0.12		—		N.M.
Mid-Continent		0.27		0.24		12.5	%

	$	0.24	$	0.22		9.1	%

⁽¹⁾	N.M. - not meaningful

Depreciation and Amortization Expense.Depreciation and amortization expense for the Current Quarter was $31.8 million compared to $22.0 million during the three months ended March 31, 2010. The increase is a result of capital expenditures made in 2010 and the acquisition of the Springridge gathering system in the Haynesville Shale.

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $9.0 million compared to $6.7 million during the three months ended March 31, 2010. This increase is primarily attributable to additional expenses resulting from the acquisition of the Springridge gathering system in the Haynesville Shale.

Interest Expense. Interest expense was $0.6 million in both the Current Quarter and the three months ended March 31, 2010. These amounts were net of $2.0 million and $0.3 million of capitalized interest during the Current Quarter and the three months ended March 31, 2010, respectively. 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 is attributable to franchise 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, other than Texas Franchise Tax.

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 annual report on Form 10-K for the year ended December 31, 2010.

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 March 31, 2011, we had a working capital deficit of $(54.4) million and as of December 31, 2010, we had positive working capital of $33.5 million. Working capital decreased from December 31, 2010 to March 31, 2011, primarily as a result of payment of the first full quarterly distribution on February 14, 2011.

Cash Flows. Net cash provided by (used in) operating activities, investing activities and financing activities of the Partnership for the three months ended March 31, 2011 and 2010, were as follows:


	Three Months Ended March 31,
	2011			2010
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	137,269		$	118,325
Investing activities	$	(106,310	)	$	(39,398	)
Financing activities	$	(48,757	)	$	(63,423	)

Operating Activities. Net cash provided by operating activities was $137.3 million for the Current Quarter compared to $118.3 million during the three months ended March 31, 2010. 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 through both capital expenditures and acquisitions.

Investing Activities. Net cash used in investing activities for the Current Quarter and the three months ended March 31, 2010, were primarily attributable to capital spending related to the expansion of gathering systems.

Financing Activities. Net cash used in financing activities decreased $14.7 million for the Current Quarter as compared to the three months ended March 31, 2010. This decrease was primarily attributable to a decrease in the use of the Partnership’s credit facility to finance operations partially offset by an increase in distributions paid to unitholders following the IPO.

Sources of Liquidity

At March 31, 2011, our potential sources of liquidity included:

•

cash on hand;

•

cash generated from operations;

•

borrowing availability 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.

Credit Facility

Our revolving bank credit facility matures in July 2015, and provides up to $750.0 million of borrowing capacity, including a sub-limit of $25.0 million for same-day swing line advances and a sub-limit of $50.0 million for letters of credit. In addition, the credit facility contains an accordion feature that allows us to increase the available borrowing capacity under the facility up to $1.0 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 percent, and the one-month London Interbank Offered Rate (“LIBOR”) plus 1.00 percent, all of which is subject to a margin that varies from 1.75 percent to 2.25 percent per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the Eurodollar rate, which is based on the LIBOR plus a margin that varies from 2.75 percent to 3.25 percent 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 percent per annum according to the most recent consolidated leverage ratio. At March 31, 2011 and December 31, 2010, there were $249.2 and $249.1 million, respectively of outstanding borrowings under such credit facility.

Notes Offering

Capital Requirements

Our business is capital-intensive, requiring significant investment to grow 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 Quarter, expansion capital expenditures totaled $88.0 million and maintenance capital expenditures totaled $18.5 million. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute 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

On January 31, 2011, the Board of Directors of our general partner declared a cash distribution to our unitholders of $0.3375 per unit for the quarter ended December 31, 2010, or $1.35 per common unit on an annualized basis, together with the corresponding distribution to the general partner. The cash distribution was paid on February 14, 2011, to unitholders of record on February 10, 2011, and to the general partner.

On April 26, 2011, the Board of Directors of our general partner declared a cash distribution to our unitholders of $0.35 per unit for the quarter ended March 31, 2011, or $1.40 per common unit on an annualized basis, together with the corresponding distribution to the general partner. The cash distribution was paid on May 13, 2011, to unitholders of record at the close of business on May 6, 2011, 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 to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. We make significant estimates which impact depreciation and assumptions regarding future net cash flows. Although we 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 the Partnership’s annual report on Form 10-K for the year ended December 31, 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;

•

oil and natural gas realized prices;

•

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;

•

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) the annual report on Form 10-K for the year ended December 31, 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.

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. 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.

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 or disparity in oil and natural gas pricing 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 in our Barnett Shale and Haynesville Shale regions 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 with Chesapeake on MMBtu-based caps on fuel, lost and unaccounted for gas on certain of our systems with respect to Chesapeake’s volumes in our Barnett Shale and Mid-Continent regions. In the event that we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel, lost or unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this replacement obligation will 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.

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 our principal executive officer and principal financial officer, 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 March 31, 2011 at the reasonable assurance level.

There was no change in our internal control over financial reporting that occurred during the Current Quarter, that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 annual report on Form 10-K for the year ended December 31, 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.

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

4.1

Indenture, dated as of April 19, 2011, by and among Chesapeake Midstream Partners, L.P., CHKM Finance Corp., and the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee.

8-K

001-34831

4.1

04/20/2011

4.2

Registration Rights Agreement, dated as of April 19, 2011, by and among Chesapeake Midstream Partners, L.P., CHKM Finance Corp., Chesapeake Midstream GP, L.L.C., the Guarantors named therein and the representatives of the Initial Purchasers named therein.

8-K

001-34831

4.2

04/20/2011

10.1

Second Amendment to 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, Swing Line Lender and the Issuing Lender, and the other Lenders party thereto, dated as of April 8, 2011.

8-K

001-34831

10.1

04/11/2011

31.1

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

31.2

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

32.1

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

32.2

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

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: May 13, 2011	By:	/s/ J. MIKE STICE
		J. Mike Stice Chief Executive Officer

Date: May 13, 2011	By:	/s/ DAVID C. SHIELS
		David C. Shiels Chief Financial Officer

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

4.1

8-K

001-34831

4.1

04/20/2011

4.2

8-K

001-34831

4.2

04/20/2011

10.1

8-K

001-34831

10.1

04/11/2011

31.1

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

31.2

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

32.1

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

32.2

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

Positive
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Legalese
Litigous
Readability	H.S. sophomore Avg

Williams Partners Inactive 10-Q2011 Q1 Quarterly report

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