WILLIAMS PARTNERS L.P. - FORM 10-Q

Attached files

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EX-32.1 - CHIEF EXECUTIVE OFFICER, CERTIFICATION PURSUANT TO SECTION 906 - WILLIAMS PARTNERS L.P.	d321001dex321.htm
EX-32.2 - CHIEF FINANCIAL OFFICER, CERTIFICATION PURSUANT TO SECTION 906 - WILLIAMS PARTNERS L.P.	d321001dex322.htm
EX-31.2 - CHIEF FINANCIAL OFFICER, CERTIFICATION PURSUANT TO SECTION 302 - WILLIAMS PARTNERS L.P.	d321001dex312.htm
EXCEL - IDEA: XBRL DOCUMENT - WILLIAMS PARTNERS L.P.	Financial_Report.xls
EX-31.1 - CHIEF EXECUTIVE OFFICER, CERTIFICATION PURSUANT TO SECTION 302 - WILLIAMS PARTNERS L.P.	d321001dex311.htm

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, 2012

[ ]	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 [X] 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 [X] Non-accelerated filer [ ] 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 4, 2012, the registrant had 78,900,747 common units outstanding.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

INDEX TO FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2012


PART I.
Financial Information
		Page
Item 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		1
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011		2
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		3
	Condensed Consolidated Statement of Changes in Partners’ Capital for the Three Months Ended March 31, 2012		4
	Notes to Condensed Consolidated Financial Statements		5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		29
Item 4.	Controls and Procedures		30

PART II.
Other Information

Item 1.	Legal Proceedings		31
Item 1A.	Risk Factors		31
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		31
Item 3.	Defaults Upon Senior Securities		31
Item 4.	Mine Safety Disclosures		31
Item 5.	Other Information		31
Item 6.	Exhibits		32

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	March 31, 2012			December 31, 2011
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	25		$	22
Accounts receivable, including $83,085 and $61,030 from related parties at March 31, 2012 and December 31, 2011, respectively		108,650			81,297
Other current assets		8,562			6,869

Total current assets		117,237			88,188

Property, plant and equipment:
Gathering systems		3,023,296			2,954,868
Other fixed assets		59,437			53,611
Less: Accumulated depreciation		(515,686	)		(480,555	)

Total property, plant and equipment, net		2,567,047			2,527,924

Investment in unconsolidated affiliates		943,109			886,558
Intangible customer relationships, net		155,796			158,621
Deferred loan costs, net		34,297			21,947

Total assets	$	3,817,486		$	3,683,238


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	8,724		$	19,443
Accrued liabilities, including $69,926 and $62,823 from related parties at March 31, 2012 and December 31, 2011, respectively		148,690			123,651

Total current liabilities		157,414			143,094

Long-term liabilities:
Long-term debt		1,188,000			1,062,900
Other liabilities		4,778			4,099


Total long-term liabilities		1,192,778			1,066,999


Commitments and contingencies (Note 8)
Partners’ Capital:
Common units (78,900,541 and 78,876,643 issued and outstanding at March 31, 2012 and December 31, 2011, respectively)		1,558,652			1,561,504
Subordinated units (69,076,122 issued and outstanding at March 31, 2012 and December 31, 2011)		866,019			869,241
General partner interest		42,623			42,400

Total partners’ capital		2,467,294			2,473,145

Total liabilities and partners’ capital	$	3,817,486		$	3,683,238

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,
	2012			2011
	($ in thousands, except per unit data)
Revenues, including revenues from affiliates (Note 6)	$	154,674		$	123,529

Operating expenses:
Operating expenses, including expenses from affiliates (Note 7)		48,682			42,561
Depreciation and amortization expense		38,438			30,938
General and administrative expense, including expenses from affiliates (Note 7)		11,478			8,946
Other operating income		(45	)		(60	)

Total operating expenses		98,553			82,385


Operating income		56,121			41,144

Other income (expense):
Income from unconsolidated affiliates		12,987			—
Interest expense (Note 4)		(15,958	)		(1,440	)
Other income		55			42

Income before income tax expense		53,205			39,746
Income tax expense		839			970

Net income	$	52,366		$	38,776

Limited partner interest in net income
Net income	$	52,366		$	38,776
Less general partner interest in net income		(1,429	)		(776	)

Limited partner interest in net income	$	50,937		$	38,000


Net income per common unit – basic and diluted	$	0.34		$	0.27
Net income per subordinated unit – basic and diluted	$	0.34		$	0.27

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,
	2012			2011
	($ in thousands)
Cash flows from operating activities:
Net income	$	52,366		$	38,776
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		38,438			30,938
Income from unconsolidated affiliates		(12,987	)		—
Other non-cash items		1,932			1,004
Changes in assets and liabilities:
(Increase) decrease in accounts receivable		(33,058	)		50,277
(Increase) decrease in other assets		(1,694	)		1,001
Increase (decrease) in accounts payable		(7,832	)		13,924
Increase in accrued liabilities		30,050			1,349

Net cash provided by operating activities		67,215			137,269


Cash flows from investing activities:
Additions to property, plant and equipment		(80,593	)		(106,521	)
Investments in unconsolidated affiliates		(45,276	)		—
Proceeds from sale of assets		421			211

Net cash used in investing activities		(125,448	)		(106,310	)


Cash flows from financing activities:

Proceeds from long-term debt borrowings		245,600			134,200
Payments on long-term debt borrowings		(870,500	)		(134,100	)
Proceeds from issuance of senior notes		750,000			—
Debt issuance costs		(13,653	)		—
Distributions to unit holders		(58,932	)		(47,581	)
Initial public offering costs		—			(1,280	)
Other adjustments		5,721			4

Net cash provided by (used in) financing activities		58,236			(48,757	)

Net increase (decrease) in cash and cash equivalents		3			(17,798	)
Cash and cash equivalents, beginning of period		22			17,816

Cash and cash equivalents, end of period	$	25		$	18


Supplemental disclosure of non-cash investing activities:
Changes in accounts payable and other liabilities related to purchases of property, plant and equipment	$	(3,565	)	$	3,536

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)


	Limited Partners						General Partner			Total
	Common			Subordinated			General Partner			Total
	($ in thousands)
Balance at December 31, 2011	$	1,561,504		$	869,241		$	42,400		$	2,473,145
Net income		27,219			23,718			1,429			52,366
Distribution to unitholders		(30,771	)		(26,940	)		(1,221	)		(58,932	)
Non-cash equity based compensation		700			—			—			700
Other Adjustments		—			—			15			15

Balance at March 31, 2012	$	1,558,652		$	866,019		$	42,623		$	2,467,294

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 and Basis of Presentation

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’s assets are located in Texas, Louisiana, Oklahoma, Kansas, Arkansas, West Virginia and Pennsylvania. The Partnership provides gathering, treating and compression services to Chesapeake Energy Corporation (“Chesapeake”), Total Gas and Power North America, Inc. (“Total”), Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”), Mitsui & Co., Ltd. (“Mitsui”) and other producers under long-term, fixed-fee contracts.

Acquisition

On December 29, 2011, the Partnership acquired from Chesapeake Midstream Development, L.P. (“CMD”) all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on the Partnership’s revolving credit facility. Through the acquisition of Appalachia Midstream, the Partnership operates 100 percent of and owns an interest in 10 gas gathering systems in the Marcellus Shale. The remaining interest in these assets is owned primarily by Statoil, Anadarko, Epsilon Energy Ltd. (“Epsilon”) and Mitsui. The 100 percent fixed-fee gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD committed to pay the Partnership quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013. Actual EBITDA exceeded the commitment in the 2012 first quarter and no payment was owed by CMD.

Holdings of Partnership Capital

At March 31, 2012, the Partnership had outstanding 78,900,541 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 30.6 percent of all outstanding limited partner interests, and Chesapeake and GIP held 46.1 percent and 23.3 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.

Basis of Presentation

The accompanying financial statements and related notes present the unaudited condensed consolidated balance sheets of the Partnership as of March 31, 2012 and December 31, 2011. They also include the unaudited condensed consolidated statements of operations and the unaudited condensed consolidated statements of cash flows for the Partnership for the three-month periods ended March 31, 2012 and 2011, and unaudited changes in partners’ capital of the Partnership for the three month period ended March 31, 2012.

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, 2011.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The results of operations for the three-month period ended March 31, 2012, are not indicative of results that may be expected for the full fiscal year.

2.	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, 2012, the Partnership paid cash distributions to its unitholders of approximately $58.9 million, representing a $0.39 per-unit distribution for the quarter ended December 31, 2011. See also Note 10 — Subsequent Events concerning distributions declared on April 27, 2012.

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 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. 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 the quarterly minimum distribution 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.

3.	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.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Basic and diluted net income per limited partner unit are 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):


	Three Months Ended March 31,
	2012			2011
Net income attributable to Chesapeake Midstream Partners, L.P.	$	52,366		$	38,776
Less general partner interest in net income		(1,429	)		(776	)

Limited partner interest in net income	$	50,937		$	38,000

Net income allocable to common units	$	27,219		$	19,020
Net income allocable to subordinated units		23,718			18,980

Limited partner interest in net income	$	50,937		$	38,000

Net income per limited partner unit – basic and diluted
Common units	$	0.34		$	0.27
Subordinated units		0.34			0.27

Total	$	0.34		$	0.27

Weighted average limited partner units outstanding used for basic and diluted net income per unit calculation
Common units		79,276,432			69,219,183
Subordinated units		69,076,122			69,076,122

Total		148,352,554			138,295,305

4.	Long-Term Debt

Revolving Credit Facility

On December 20, 2011, the Partnership amended its revolving credit facility to increase total borrowing capacity. The revolving credit facility, as amended to date, provides the Partnership up to $1 billion of borrowing capacity and includes a sub-limit up to $50 million for same-day swing line advances and a sub-limit up to $50 million for letters of credit. In addition, the revolving credit facility contains an accordion feature that allows the Partnership to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. The revolving credit facility matures in June 2016. As of March 31, 2012 and December 31, 2011, respectively, the Partnership had approximately $88.0 and $712.9 million of borrowings outstanding under its revolving credit facility.

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Partnership reaches investment grade status, the Partnership will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while the Partnership is subject to the leverage-based pricing grid, according to the Partnership’s leverage ratio and (b) 0.20 percent to 0.35 percent per annum while the Partnership is subject to the ratings-based pricing grid, according to its senior unsecured long-term debt ratings.

Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit the Partnership and its subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of the Partnership’s assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If the 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 revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness the Partnership may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit the Partnership’s ability, as well as the ability of certain of its subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require the Partnership to maintain a consolidated leverage ratio, and an EBITDA to interest expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for the Partnership to maintain the EBITDA-to-interest-expense ratio if the Partnership reaches investment grade status. The revolving credit facility agreement also requires the Partnership to maintain a consolidated leverage ratio of 5.0 to 1.0 (or 5.5 to 1.0 during an approximate two-quarter period following the completion of certain acquisitions). The Partnership was in compliance with all covenants under the agreement at March 31, 2012.

Senior Notes

On January 11, 2012, the Partnership and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). The Partnership used a portion of the net proceeds to repay all borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $14.1 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, the Partnership and CHKM Finance Corp completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 ( the “2021 Notes”). The Partnership used a portion of the net proceeds to repay borrowings outstanding under its revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. The 2021 Notes will mature on April 15, 2021 and interest is payable on April 15 and October 15 of each year. The Partnership has the option to redeem all or a portion of the notes at any time on or after January 15, 2017, in the case of the 2022 Notes and April 15, 2015, in the case of the 2021 Notes at the redemption prices specified in the applicable indenture, plus accrued and unpaid interest. The Partnership may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, the Partnership may redeem up to 35 percent of the 2022 Notes and the 2021 Notes prior to January 15, 2015 and April 15, 2014, respectively, under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit the Partnership’s ability and the ability of certain of the Partnership’s subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase the Partnership’s units, or

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

redeem or purchase the Partnership’s subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to the Partnership; (7) consolidate, merge or transfer all or substantially all of the Partnership’s or certain of the Partnership’s subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indentures, has occurred or is continuing, many of these covenants will terminate.

The Partnership, as the parent company, has no independent assets or operations. The Partnership’s operations are conducted by its subsidiaries through its operating company subsidiary, Chesapeake MLP Operating, L.L.C. Each of Chesapeake MLP Operating, L.L.C. and the Partnership’s other subsidiaries is a guarantor, other than CHKM Finance Corp., an indirect wholly owned subsidiary of the Partnership whose sole purpose is to act as co-issuer of any debt securities. Each guarantor is a wholly owned subsidiary of the Partnership. The guarantees registered under the registration statement are full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the Indenture. There are no significant restrictions on the ability of the Partnership or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of the Partnership or a guarantor represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

Capitalized Interest

For the three-month periods ended March 31, 2012 and March 31, 2011, interest expense was net of capitalized interest of $2.2 million and $2.0 million, respectively.

5.	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 current fair value at the vest date and recognized 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 $1.0 million and $1.1 million for the Partnership during the three-month periods ended March 31, 2012 and March 31, 2011, 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, 2012:


	Units			Value per Unit
Restricted units outstanding at beginning of period		273,258		$	28.50
Granted		145,476			29.21
Vested		(23,898	)		28.52
Forfeited		(17,094	)		28.55

Restricted units outstanding at end of period		377,742		$	28.77

6.	Major Customers and Concentration of Credit Risk

Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake, accounted for $125.5 million and $103.3 million of the Partnership’s revenues for the three-month periods ended March 31, 2012 and March 31, 2011, respectively. Total accounted for $22.8 million and $16.4 million of the Partnership’s revenues for the three-month periods ended March 31, 2012 and March 31, 2011, 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, 2012 and December 31, 2011, cash and cash equivalents were invested in a non-interest bearing account and money market funds with investment grade ratings.

7.	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 cap based on volumes of natural gas gathered. The cap is calculated as the lesser of $0.03065/Mcf gathered or actual corporate overhead costs, excluding those overhead costs that are billed directly to the Partnership. General and administrative charges for the partnership were $5.9 million and $5.7 million for the three-month periods ended March 31, 2012 and March 31, 2011, respectively.

Chesapeake and its affiliates also provide compression services to the Partnership. The Partnership is charged for compressor rentals based on long-term compressor rental agreements with MidCon Compression, LLC, a wholly owned indirect subsidiary of Chesapeake. For the three-month periods ended March 31, 2012 and March 31, 2011, compressor rental charges from affiliates were $15.7 million and $14.2 million, respectively. These charges are included in operating expenses in the accompanying condensed consolidated statements of operations.

See also Note 6 — 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)

8.	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 Partnership’s 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, 2012 or December 31, 2011.

9.	Fair Value Measures

The fair-value-measurement standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which they are observable. The three levels of the fair value hierarchy are as follows:

Level 1 — inputs represent quoted prices in active markets for identical assets or liabilities.

Level 2 — inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs).

Level 3 — inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an estimate of future cash flows used in management’s internally developed present value of future cash flows model that underlies the fair value measurement).

Nonfinancial assets and liabilities initially measured at fair value include third-party business combinations, impaired long-lived assets (asset groups), and initial recognition of asset retirement obligations.

The fair value of debt is the estimated amount the Partnership would have to pay to repurchase its debt, including any premium or discount attributable to the difference between the stated interest rate and market rate of interest at the balance sheet date. Fair values are based on quoted market prices or average valuations of similar debt instruments at the balance sheet date for those debt instruments for which quoted market prices are not available. 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.


	March 31, 2012				December 31, 2011
	Carrying amount		Fair value (Level 2)		Carrying amount		Fair value (Level 2)
	($ in thousands)
Financial liabilities:
Revolving credit facility	$	88,000	$	88,000	$	712,900	$	712,900
2021 Notes		350,000		349,783		350,000		350,221
2022 Notes		750,000		756,563		—		—

CHESAPEAKE MIDSTREAM PARTNERS, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

The carrying amount of cash and cash equivalents (Level 1), accounts receivable and accounts payable reported on the balance sheet approximates fair value due to their short-term maturities.

10.

Subsequent Events

Distribution

On April 27, 2012, the Board of Directors of the Partnership’s general partner declared a cash distribution to the Partnership’s unitholders of $0.405 per unit together with the corresponding distribution to the general partner. The cash distribution will be paid on May 15, 2012, to unitholders of record at the close of business on May 8, 2012, and to the general partner.

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, 2012 (the “Current Quarter”) and March 31, 2011 (the “Prior Quarter”):


	Three Months Ended March 31,
	2012			2011
	(In thousands, except operational data)
Revenues⁽¹⁾	$	154,674		$	123,529

Operating expenses		48,682			42,561
Depreciation and amortization expense		38,438			30,938
General and administrative expense		11,478			8,946
Other operating income		(45	)		(60	)

Total operating expenses		98,553			82,385

Operating income		56,121			41,144
Income from unconsolidated affiliates		12,987			—
Interest expense		(15,958	)		(1,440	)
Other income		55			42

Income before income tax expense		53,205			39,746
Income tax expense		839			970

Net income	$	52,366		$	38,776

Key Performance Metrics:
Adjusted EBITDA⁽²⁾	$	118,429		$	72,064
Distributable cash flow⁽²⁾	$	84,435		$	51,974
Operational Data⁽³⁾ :
Wells connected during period		197			155
Wells connected at end of period		5,443			4,510
Throughput, Bcf per day		2.802			2.008
Miles of pipe at end of period		3,953			3,386
Gas compression (horsepower) at end of period		324,951			248,314

⁽¹⁾

If 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 relevant 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 thousand cubic feet (“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 caption How We Evaluate Our Operations within this Part I, Item 2.

⁽³⁾	Operational data includes the gross results for the Marcellus Shale region except for throughput which represents the net throughput allocated to the Partnership’s interest.

We are a growth-oriented publicly traded Delaware limited partnership formed by Chesapeake and GIP to own, operate, develop and acquire natural gas, natural gas liquids and oil 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, West Virginia and Pennsylvania. We provide gathering, treating and compression services to Chesapeake, Total, Statoil ASA (“Statoil”), Anadarko Petroleum Corporation (“Anadarko”) and Mitsui & Co., Ltd. (“Mitsui”) and other producers under long-term, fixed-fee contracts.

Our gathering systems operate in our Barnett Shale region in north-central Texas, our Haynesville Shale region in northwest Louisiana, our Marcellus Shale region in Pennsylvania and West Virginia, and our Mid-Continent region which includes the Anadarko, Arkoma, Delaware and Permian Basins. We service approximately 2,285 wells in the core of the Barnett Shale region. Our Springridge gathering system services approximately 222 wells in one of the core areas of the Haynesville Shale. In the Marcellus Shale region, we own an equity interest in 10 gas gathering systems. 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. For the Current Quarter our assets gathered approximately 2.802 billion cubic feet (“Bcf”) of natural gas per day, on a net basis. In total, we operate systems consisting of approximately 3,953 miles of gathering pipelines, servicing approximately 5,443 natural gas wells.

We generated approximately 67 percent of our revenues from our gathering systems in our Barnett Shale region, approximately 12 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. Revenue from the Marcellus Shale region is accounted for as part of our equity investment in these assets.

Acquisition

Marcellus Acquisition. On December 29, 2011, we acquired from CMD all of the issued and outstanding common units of Appalachia Midstream Services, L.L.C. (“Appalachia Midstream”) for total consideration of $879.3 million, consisting of 9,791,605 common units and $600.0 million in cash that was financed with a draw on our revolving credit facility. Through the acquisition of Appalachia Midstream, we operate 100 percent of and own an interest in 10 gas gathering systems in the Marcellus Shale. The remaining interest in these assets is owned primarily by Statoil, Anadarko, Epsilon Energy Ltd. (“Epsilon”) and Mitsui. The gathering agreements include significant acreage dedications and annual fee redeterminations. In addition, CMD committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets, with the quarterly targets adding to a total of $100 million in 2012 and $150 million in 2013. Actual EBITDA exceeded the commitment in the 2012 first quarter and no payment was owed by CMD.

Our Gas Gathering Agreements

We generate substantially all of our revenues through long-term, fixed-fee natural gas gathering, treating and compression contracts that limit our direct commodity price exposure. We are party to (i) a 20-year gas gathering agreement with respect to the Barnett Shale and the Mid-Continent region with certain subsidiaries of Chesapeake that was entered into in connection with the creation of our predecessor in September 2009, (ii) a 20-year gas gathering agreement with respect to the Barnett Shale with Total that was entered into in connection with an upstream joint venture transaction between Chesapeake and Total E&P in January 2010, (iii) a 10-year gas gathering agreement with certain subsidiaries of Chesapeake that was entered into concurrent with the closing of our acquisition of the Springridge gas gathering system in the Haynesville Shale in December 2010 and (iv) through Appalachia Midstream, 15-year gas gathering agreements with certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief Oil & Gas (“Chief”) that we acquired in connection with our acquisition of Appalachia Midstream in December 2011.

Future revenues under our gas gathering agreements will be derived pursuant to terms that will vary depending on the applicable operating region. The following outlines the key economic provisions of our gas gathering agreements by region.

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

•

Gathering, Treating and Compression Services. We gather, treat and compress natural gas for Chesapeake and Total within the Barnett Shale region in exchange for specified fees per Mcf for natural gas gathered on our gathering systems that are based on the pressure at the various points where our gathering systems 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 is attributed to Chesapeake, and approximately 25 percent is attributed to Total. The minimum volume commitments increase, on average, approximately three percent per year. If 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. If 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 request a redetermination of the Barnett Shale fee during a six-month period beginning September 30, 2011 and a two-year period beginning on September 30, 2014. We have not redetermined rates as of March 31, 2012. Volume and revenue performance continues to be very strong in the region driven by significant well connect activity in the second half of 2011. We continue to maintain the right to redetermine fees as part of the first contractual redetermination period. The fee redetermination mechanism is intended to support a return on our invested capital. If a fee redetermination is requested, we determine an adjustment (upward or downward) to our Barnett Shale fee with Chesapeake and Total based on the factors specified in our gas gathering agreements, including, but not limited to: (i) differences between our actual capital expenditures, compression expenses and revenues as of the redetermination date and the scheduled estimates of these amounts for the minimum volume commitment period made as of September 30, 2009 and (ii) differences between the revised estimates of our capital expenditures, compression expenses and revenues for the remainder of the minimum volume commitment period forecast as of the redetermination date and scheduled estimates thereof for the minimum volume commitment period made as of September 30, 2009. The cumulative upward or downward adjustment for the Barnett Shale region is capped at 27.5 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 is 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 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 and Lost and Unaccounted For Gas. We have agreed with Chesapeake and Total on caps on fuel and lost and unaccounted for gas on our systems, both on an individual basis and an aggregate basis, with respect to Chesapeake’s and Total’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. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and 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 these systems 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 systems attributable to Chesapeake’s production. To the extent natural gas gathered on our systems 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 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 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 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 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 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 systems. 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 and Lost and Unaccounted For Gas. We have agreed with Chesapeake on caps on fuel and lost and unaccounted for gas on our systems with respect to Chesapeake’s volumes. These caps do not apply to one of our compressor stations due to its historical performance relative to the caps. This station will be reviewed periodically to determine whether changes have occurred that would make it suitable for inclusion. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel or lost and 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.

Marcellus Shale Region. Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chesapeake, Statoil, Anadarko, Epsilon, Mitsui and Chief, we have agreed to provide the following services in our Marcellus Shale region for our proportionate share (based on our ownership interest in the applicable systems) of the fees and obligations outlined below:

•

Gathering and Compression Services. We gather and compress natural gas in exchange for fees per million British thermal units (“MMBtu”) for natural gas gathered and per MMBtu for natural gas compressed. The gathering fees are redetermined annually, as described below. The compression fees escalate on January 1 of each year based on the consumer price index. In addition, CMD has committed to pay us quarterly any shortfall between the actual EBITDA from these assets and specified quarterly targets. The targets add to a total of $100 million in 2012 and $150 million in 2013. These amounts represent the minimum amount of EBITDA we will recognize in each year with the potential that throughput for these systems would generate EBITDA in excess of the guaranteed amounts.

•

Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, the shippers and producers have agreed to dedicate all of the natural gas owned or controlled by them and produced from or attributable to existing and future wells with a surface location within the designated dedicated areas.

•

Fee Redetermination. Each January 1, gathering fees for each gathering system under the gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui are redetermined and adjusted based on the factors specified in the gas gathering agreements, including our capital expenditures for the system, the total revenues and total expenses for the system and the targeted pre-income tax rate of return on capital invested. There is no cap on these fee adjustments. Each January 1, gathering fees for each gathering system under the gas gathering agreement with Chief are adjusted based on the applicable producer price index. The change in the amount of the gathering fees under the Chief agreement is not to exceed 3 percent in any one year.

•

Well Connections. We have the option to connect to new wells within the dedicated acreage. If we elect not to connect to any new well within the dedicated acreage, the shipper for such well may elect to have such well, and any subsequent wells within a two-mile radius (in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui) or a one-mile radius (in the case of Chief) of the surface location of such well, permanently released from the dedication area, or the shipper may elect to construct, at the shipper’s expense, a gathering system to connect to such well (and wells within a one-mile radius of such well in the case of Chesapeake, Statoil, Anadarko, Epsilon and Mitsui), in which case the shipper would pay us a reduced gathering fee for natural gas we

receive through the shipper-installed asset. Alternatively, the shipper may require us to enter into an agreement pursuant to which we would construct the gathering system to connect to the well in exchange for a reimbursement by the shipper of the costs we incur in connection therewith. The shipper may elect to connect wells outside the dedicated area at its sole expense and pay us a reduced gathering fee for natural gas we receive from such wells, but gas from such outside wells will not be afforded the same priority as gas produced from wells located within the dedicated area.

•

Fuel and Lost and Unaccounted For Gas. Under our gas gathering agreements with Chesapeake, Statoil, Anadarko, Epsilon and Mitsui, we have agreed on caps on fuel and lost and unaccounted for gas on the systems. If we exceed a permitted cap in any covered period, we must provide a cost estimate for a remedy that is reasonably expected to prevent exceeding the permitted cap in the future. At the election of the shippers we may pay such costs (which costs would then be included in the gathering fee redetermination) or the shippers may pay the costs. If we exceed a permitted cap and do not provide a proposal to the shippers to prevent exceeding the cap in the future within the required time period, we may incur our proportionate share (based on our ownership interest in the applicable system) of significant fees in connection with the natural gas used as fuel or lost and unaccounted for in excess of such cap based on then current natural gas prices. Accordingly, this may subject us to direct commodity price risk.

Under gas gathering agreements between Appalachia Midstream and certain subsidiaries of Chief, the shipper on each system is to furnish to us, at the shipper’s sole cost and expense, all necessary fuel gas to operate the system. Gas volumes lost solely due to our actions or inactions constituting gross negligence or willful misconduct are our sole responsibility. Additionally, we will bear the cost of natural gas lost in excess of one percent due to our failure to maintain adequate corrosion protection. If we lose natural gas due to our gross negligence or willful misconduct or our failure to maintain an adequate corrosion protection system, we may incur significant expenses in connection with the cost of the lost natural gas. Our responsibility for the cost of the lost gas 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. We refer to the fees collectively as the Mid-Continent fee. The Mid-Continent fees for these systems are subject to an annual two and a half percent rate escalation at the beginning of each year.

•

Fee Redetermination. The Mid-Continent fees are redetermined at the beginning of each year through 2019. We and Chesapeake 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.

•

Fuel and Lost and Unaccounted For Gas. We have agreed with Chesapeake on caps on fuel and 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. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the 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 will subject us to direct commodity price risk.

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.

If one of the counterparties to the gas gathering agreements sells, transfers or otherwise disposes to a third party properties within the Partnership’s acreage dedications, it will be required to cause the third party to either enter into the existing gas gathering agreement or enter into a new gas gathering agreement with the Partnership on substantially similar terms to the existing gas gathering agreement with the applicable party.

Other Arrangements

Business Opportunities. Pursuant to our services 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 the 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 in the Barnett Shale and Mid-Continent regions 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 the lesser of $0.03065 per Mcf of natural gas that we gather, treat or compress or actual corporate overhead costs, excluding those overhead costs that are billed directly to us. The $0.03065 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 if 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, Marcellus 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. Our volumes are supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total in the case of our Barnett Shale region and Chesapeake in the case of our Haynesville Shale region. 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, 2012 and 2011, Chesapeake accounted for approximately 81.2 and 84.3 percent, respectively, of the natural gas volumes on our gathering systems and 81.1 and 83.7 percent, respectively, of our revenues in our Barnett Shale, Haynesville Shale and Mid-Continent regions. In our Marcellus Shale region, Chesapeake accounted for approximately 54.1 percent of the natural gas volumes on our gathering systems. Revenue from the Marcellus Shale region is accounted for as part of our equity investment in those assets. Across all operating regions, we earned approximately 75 percent of our fees from Chesapeake and 25 percent from other producer customers.

Our revenues are 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 without compromising environmental protection and employee safety. Operating 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 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

We define Adjusted EBITDA as net income (loss) before income tax expense, interest expense, depreciation and amortization expense and certain other items management believes affect the comparability of operating results.

Adjusted EBITDA is a 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 capital structure, historical cost basis, or financing methods;

•

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

•

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

•

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

We believe it is appropriate to exclude certain items from EBITDA because we believe these items affect the comparability of operating results. We believe that the presentation of Adjusted EBITDA in this report provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to Adjusted EBITDA is net income.

Distributable Cash Flow

Our Partnership agreement defines Distributable Cash Flow (“DCF”) as Adjusted EBITDA attributable to the Partnership adjusted for:

•

Addition of interest income;

•

Subtraction of net cash paid for interest expense;

•

Subtraction of maintenance capital expenditures; and

•

Subtraction of income taxes.

DCF is an important non-GAAP financial measure for our limited partners since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flows at a level that can sustain or support an increase in our quarterly cash distributions. DCF is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is in part measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. The GAAP measure most directly comparable to DCF is net cash provided by operating activities.

Reconciliation to GAAP measures

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. Adjusted EBITDA and distributable cash flow are presented because they are helpful to management, industry analysts, investors, lenders and rating agencies and may be used to assess the financial performance and operating results of our fundamental business activities. The GAAP measures most directly comparable to Adjusted EBITDA and distributable cash flow are net income and net cash provided by operating activities. Our non-GAAP financial measures of Adjusted EBITDA and distributable cash flow should not be considered as an alternative to GAAP net income or net cash provided by operating activities. Each of Adjusted EBITDA and distributable cash flow has important limitations as an analytical tool because it excludes some but not all items that affect net income and net cash provided by operating activities. You should not consider either Adjusted EBITDA or distributable cash flow in isolation or as a substitute for analysis of our results as

reported under GAAP. Because Adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and distributable cash flow may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

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


	Three Months Ended March 31,
	2012			2011
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net income:
Net income	$	52,366		$	38,776
Interest expense		15,958			1,440
Income tax expense		839			970
Depreciation and amortization expense		38,438			30,938
Other		(45	)		(60	)
Income from unconsolidated affiliates		(12,987	)		—
EBITDA from unconsolidated affiliates⁽¹⁾		23,860			—

Adjusted EBITDA	$	118,429		$	72,064

Maintenance capital expenditures		(18,500	)		(18,500	)
Cash portion of interest expense		(14,655	)		(620	)
Income tax expense		(839	)		(970	)

Distributable Cash Flow	$	84,435		$	51,974


	Three Months Ended March 31,
	2012			2011
	($ in thousands)
Reconciliation of adjusted EBITDA and distributable cash flow to net cash provided by operating activities:
Cash Provided By Operating Activities	$	67,215		$	137,269
Changes in assets and liabilities		12,534			(66,551	)
Interest expense		15,958			1,440
Income tax expense		839			970
Other non-cash items		(1,977	)		(1,064	)
EBITDA from unconsolidated affiliates⁽¹⁾		23,860			—

Adjusted EBITDA	$	118,429		$	72,064

Maintenance capital expenditures		(18,500	)		(18,500	)
Cash portion of interest expense		(14,655	)		(620	)
Income tax expense		(839	)		(970	)

Distributable Cash Flow	$	84,435		$	51,974

		xxx.xx.x			xxx.xx.x
	Three Months Ended March 31,
⁽¹⁾ Marcellus’ Adjusted EBITDA is calculated as follows:	2012			2011
	($ in thousands)
Net Income	$	12,987			—
Depreciation and amortization expense		10,901			—
Other		(28	)		—

EBITDA from unconsolidated affiliates	$	23,860			—

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 $154.7 million compared to $123.5 million during the Prior Quarter, primarily as a result of increased throughput in our Barnett Shale region. Barnett Shale throughput increased 33.5 percent due to additional throughput from wells connected in 2011. The increase in Barnett Shale revenue was slightly higher at 36.0 percent as a result of a two percent annual fee escalation that took effect on January 1, 2012. Haynesville Shale throughput was down 15.3 percent as a result of Chesapeake curtailing production in this region due to low natural gas prices. Revenue in the Haynesville Shale region was down 7.9 percent as a 2.5 percent annual fee escalation and some temporary third-party throughput at higher fees partially offset the volume decrease. Mid-Continent volume for the Current Quarter was flat; however, a 2.5 percent annual fee escalation and a 15 percent fee increase due to annual contractual fee redetermination helped Mid-Continent revenue increase more than 20 percent.

We have contractual minimum volume commitments from Chesapeake and Total in the Barnett Shale and from Chesapeake in the Haynesville Shale. The minimum volume commitments are measured annually and any associated revenue is recognized in the fourth quarter of each year. Throughput in these regions during the Current Quarter was above minimum volume commitment levels.

The following table reflects the Partnership’s revenues and throughput by region for the three months ended March 31, 2012 and 2011 (please note that Marcellus Shale throughput is excluded from the table below as the financial results of the Marcellus Shale are reported as an equity investment – see Income from Unconsolidated Affiliates in this Results of Operations section of Management’s Discussion and Analysis):


	Three Months Ended March 31,
	2012		2011		% Change⁽¹⁾
	(In thousands, except percentages and throughput data)
Revenue:
Barnett Shale	$	103,432	$	76,027		36.0	%
Haynesville Shale		19,257		20,916		(7.9	)
Mid-Continent		31,985		26,586		20.3

	$	154,674	$	123,529		25.2	%

Throughput (Bcf):
Barnett Shale		116.4		87.2		33.5	%
Haynesville Shale		37.7		44.5		(15.3	)
Mid-Continent		48.7		49.0		(0.6	)

		202.8		180.7		12.2	%

Operating Expenses. For the Current Quarter, operating expenses were $0.24 per Mcf compared to $0.24 per Mcf during the Prior Quarter. In the Barnett Shale region, throughput has increased and operating expenses have increased in order to generate the additional throughput. We have reduced operating expense in the Haynesville Shale in response to the reduction in throughput in this region; however, we have fixed costs in this area causing the expense per Mcf to increase temporarily. In the Mid-Continent region, operating expenses have increased as we prepare for increased activity in this liquids-rich region.

The following table reflects our operating expenses and operating expenses per Mcf of throughput by region for the three months ended March 31, 2012 and March 31, 2011 (please note that Marcellus Shale expenses are excluded from the table below as the financial results of the Marcellus Shale are reported as an equity investment. See Income from Unconsolidated Affiliates in this Results of Operations section of Management’s Discussion and Analysis):


	Three Months Ended March 31,
	2012		2011		% Change⁽¹⁾
	(In thousands, except percentages and per Mcf data)
Operating Expenses:
Barnett Shale	$	29,760	$	23,685		25.6	%
Haynesville Shale		4,821		5,512		(12.5	)
Mid-Continent		14,101		13,364		5.5

	$	48,682	$	42,561		14.4	%

Expenses ($ per Mcf):
Barnett Shale	$	0.26	$	0.27		(3.7	)%
Haynesville Shale		0.13		0.12		8.3
Mid-Continent		0.29		0.27		7.4

	$	0.24	$	0.24		—	%

Depreciation and Amortization Expense. Depreciation expense for the Current Quarter was $35.6 million compared to $28.1 million during the Prior Quarter. Amortization expense for the Current Quarter and Prior Quarter was $2.8 million. The increase is a result of capital expenditures made in 2011.

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $11.5 million compared to $9.0 million during the Prior Quarter. This increase is primarily attributable to additional expenses resulting from the acquisition of Appalachia Midstream in the Marcellus Shale.

Income from Unconsolidated Affiliates. On December 29, 2011, we acquired all of the issued and outstanding common units of Appalachia Midstream which operates 100 percent of and owns an interest in 10 gas gathering systems in the Marcellus Shale in Pennsylvania and West Virginia. The remaining interest in these assets is owned primarily by Statoil, Anadarko, Epsilo and Mitsui. In the Current Quarter, we connected 68 new wells and our net throughput was 0.574 Bcf per day. Income from unconsolidated affiliates was $13.0 million for the Current Quarter. The following table summarizes the results of the Marcellus Shale assets (net to our interest) for the Current Quarter:


	Three Months Ended March 31, 2012
	(In thousands, except per Bcf and $ per Mcf data)
Marcellus Shale:
Revenue	$	29,259
Throughput (Bcf)		52.2
Operating expenses	$	3,734
Expenses ($ per Mcf)		0.07

Interest Expense. Interest expense was $16.0 million for the Current Quarter compared to $1.4 million for the Prior Quarter. These amounts were net of $2.2 million and $2.0 million of capitalized interest during the Current Quarter and the Prior Quarter, respectively. The increase is related to interest expense on the senior notes issued in April 2011 and January 2012. Interest expense is related to borrowings under our revolving credit facility and senior notes. Interest expense also includes commitment fees on the unused portion of our credit facility and amortization of debt issuance costs.

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. See Risk Factors in our annual report on Form 10-K for the year ended December 31, 2011.

Working Capital (Deficit). Working capital, defined as the amount by which current assets exceed current liabilities and may indicate the potential need for short-term funding. As of March 31, 2012, we had a working capital deficit of $(40.2) million and as of December 31, 2011, we had a working capital deficit of $(54.9) million.

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, 2012 and 2011, were as follows:


	Three Months Ended March 31,
	2012			2011
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	67,215		$	137,269
Investing activities	$	(125,448	)	$	(106,310	)
Financing activities	$	58,236		$	(48,757	)

Operating Activities. Net cash provided by operating activities was $67.2 million for the Current Quarter compared to $137.3 million during the Prior Quarter. Changes in cash flow from operations are largely due to the same factors that affect our net income, excluding various non-cash items such as depreciation, amortization and gains or losses on the sales of fixed assets. See additional discussion in the Results of Operations section above in the Management’s Discussion and Analysis.

Investing Activities. Net cash used in investing activities for the Current Quarter increased $19.1 million compared to the Prior Quarter. Approximately $125.5 million was used in investing activities during 2012. This amount included approximately $80.6 million in additions to property, plant and equipment and $45.3 in additions to our investment in unconsolidated affiliates.

Financing Activities. Net cash provided by (used in) financing activities increased $107.0 million for the Current Quarter as compared to the Prior Quarter. This increase was primarily attributable to an increase in net borrowings period-over-period.

Sources of Liquidity

At March 31, 2012, our potential sources of liquidity included:

•

cash on hand;

•

cash generated from operations;

•

borrowing availability under our revolving credit facility; and

•

capital raised through debt and equity markets.

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.

Cash flow from operations is a significant source of liquidity we use to fund capital expenditures, pay distributions and service debt. We have historically and expect in the future to use capacity on our credit facility and the capital markets to fund growth capital and acquire natural gas, natural gas liquids and oil gathering systems and other midstream energy assets, allowing us to execute our growth strategy.

Revolving Credit Facility

On December 20, 2011 we amended our revolving credit facility to increase total borrowing capacity. The revolving credit facility, as amended to date, provides us up to $1 billion of borrowing capacity and includes a sub-limit up to $50 million for same-day swing line advances and a sub-limit up to $50 million for letters of credit. In addition, the revolving credit facility contains an accordion feature that allows us to increase the available borrowing capacity under the facility up to $1.25 billion, subject to the satisfaction of certain conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. The revolving credit facility matures in June 2016. As of March 31, 2012 and December 31, 2011, respectively, we had approximately $88.0 million and $712.9 million of borrowings outstanding under our revolving credit facility.

Borrowings under the revolving credit facility are available to fund working capital, finance capital expenditures and acquisitions, provide for the issuance of letters of credit and for general partnership purposes. The revolving credit facility is secured by all of our assets, and loans thereunder (other than swing line loans) bear interest at our option at either (i) the greater of (a) the reference rate of Wells Fargo Bank, NA, (b) the federal funds effective rate plus 0.50 percent or (c) the Eurodollar rate which is based on the London Interbank Offered Rate (LIBOR), plus 1.00 percent, each of which is subject to a margin that varies from 0.625 percent to 1.50 percent per annum, according to the Partnership’s leverage ratio (as defined in the agreement), or (ii) the Eurodollar rate plus a margin that varies from 1.625 percent to 2.50 percent per annum, according to our leverage ratio. If we reach investment grade status, we will have the option to release the security under the credit facility and amounts borrowed will bear interest under a specified ratings-based pricing grid. The unused portion of the credit facility is subject to commitment fees of (a) 0.25 percent to 0.40 percent per annum while we are subject to the leverage-based pricing grid, according to our leverage ratio and (b) 0.20 percent to 0.35 percent per annum while we are subject to the ratings-based pricing grid, according to our senior unsecured long-term debt ratings.

Our 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). We are in compliance with all covenants under the agreement at March 31, 2012.

Additionally, the revolving credit facility contains various covenants and restrictive provisions which limit us and our subsidiaries’ ability to incur additional indebtedness, guarantees and/or liens; consolidate, merge or transfer all or substantially all of our assets; make certain investments, acquisitions or other restricted payments; modify certain material agreements; engage in certain types of transactions with affiliates; dispose of assets; and prepay certain indebtedness. If we fail to perform our obligations under these and other covenants, the revolving credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the revolving credit facility could be declared immediately due and payable. The revolving credit facility also has cross default provisions that apply to any other indebtedness we may have with an outstanding principal amount in excess of $15 million.

The revolving credit facility agreement contains certain negative covenants that (i) limit our ability, as well as the ability of certain of our subsidiaries, among other things, to enter into hedging arrangements and create liens and (ii) require us to maintain a consolidated leverage ratio, and an EBITDA-to-interest-expense ratio, in each case as described in the credit facility agreement. The revolving credit facility agreement also provides for the discontinuance of the requirement for us to maintain the EBITDA-to-interest-expense ratio if we reach investment grade status. The revolving credit facility agreement also requires us to maintain a consolidated leverage ratio of 5.0 to 1.0 (or 5.5 to 1.0 during an approximate two-quarter period following the completion of certain acquisitions).

Senior Notes

On January 11, 2012, we and CHKM Finance Corp., a wholly owned subsidiary of Chesapeake MLP Operating, L.L.C., completed a private placement of $750.0 million in aggregate principal amount of 6.125 percent senior notes due 2022 (the “2022 Notes”). We used a portion of the net proceeds to repay all borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $14.1 million are being amortized over the life of the 2022 Notes.

On April 19, 2011, we and CHKM Finance Corp completed a private placement of $350.0 million in aggregate principal amount of 5.875 percent senior notes due 2021 (the “2021 Notes”). We used a portion of the net proceeds to repay borrowings outstanding under our revolving credit facility and used the balance for general partnership purposes. Debt issuance costs of $7.8 million are being amortized over the life of the 2021 Notes.

The 2022 Notes will mature on July 15, 2022 and interest is payable on January 15 and July 15 of each year. The 2021 Notes will mature on April 15, 2021 and interest is payable on April 15 and October 15 of each year. We have the option to redeem all or a portion of the 2022 and 2021 Notes at any time on or after January 15, 2017, in the case of the 2022 Notes and April 15, 2015, in the case of the 2021 Notes at the redemption prices specified in the applicable indenture, plus accrued and unpaid interest. We may also redeem the 2021 Notes, in whole or in part, at a “make-whole” redemption price specified in the indenture, plus accrued and unpaid interest, at any time prior to April 15, 2015. In addition, we may redeem up to 35 percent of the 2022 Notes and the 2021 Notes prior to January 15, 2015 and April 15, 2014, respectively, under certain circumstances with the net cash proceeds from certain equity offerings.

The 2022 Notes and the 2021 Notes indentures contain covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to: (1) sell assets including equity interests in its subsidiaries; (2) pay distributions on, redeem or purchase our units, or redeem or purchase our subordinated debt; (3) make investments; (4) incur or guarantee additional indebtedness or issue preferred units; (5) create or incur certain liens; (6) enter into agreements that restrict distributions or other payments from certain subsidiaries to us; (7) consolidate, merge or transfer all or substantially all of our or certain of our subsidiaries’ assets; (8) engage in transactions with affiliates; and (9) create unrestricted subsidiaries. These covenants are subject to important exceptions and qualifications. If the 2022 Notes or the 2021 Notes achieve an investment grade rating from either of Moody’s Investors Service, Inc. or Standard & Poor’s Ratings Services and no default, as defined in the indentures, has occurred or is continuing, many of these covenants will terminate.

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 $143.4 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

Declaration
Date

Record
Date

Distribution
Date

Distribution
Declared

Total Cash
Distribution

($ in thousands)

2012

First quarter

April 27, 2012

May 8, 2012

May 15, 2012

0.4050

61,543

2011

Fourth quarter

January 27, 2012

February 7, 2012

February 14, 2012

0.3900

58,932

Third quarter

October 28, 2011

November 7, 2011

November 14, 2011

0.3750

52,868

Second quarter

July 26, 2011

August 5, 2011

August 12, 2011

0.3625

51,106

First quarter

April 26, 2011

May 6, 2011

May 13, 2011

0.3500

49,343

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 our annual report on Form 10-K for the year ended December 31, 2011.

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, Total and other producers for a substantial majority of our revenues;

•

the impact on our growth strategy and ability to increase cash distributions if Chesapeake, Total or other producers 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, Total or other producers;

•

the availability, terms and effects of acquisitions from Chesapeake;

•

our potential inability to maintain existing distribution amounts or 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 diversification; and

•

legislative or regulatory changes, including changes in environmental regulations, environmental risks, regulations by the Federal Energy Regulatory Commission 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) Part I, “Item 1A. Risk Factors” and elsewhere in our annual report on Form 10-K for the year ended December 31, 2011, (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, Total and other producers for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake, Total or other producers 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, we are also subject to the risk that one or more of these customers default on its obligations under its gas gathering agreements with us. Not all of our counterparties under our gas gathering agreements are rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

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 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 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 with our producer customers on caps on fuel and lost and unaccounted for gas on certain of our gathering systems in our operating regions. If we exceed a permitted cap in any covered period, we may incur significant expenses to replace the natural gas used as fuel and 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 Rules 13a-15(b) and 15d-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 the principal executive officer and principal financial officer of our general partner, 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 recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. 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 at a reasonable level of assurance as of March 31, 2012.

No changes in the Partnership’s internal control over financial reporting occurred during the quarter ended March 31, 2012 that have materially affected, or are reasonably likely to materially affect, the Partnership’s 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, 2011. 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.

Mine Safety Disclosure

Not applicable.

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 January 11, 2012, 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

01/11/2012

4.2

Registration Rights Agreement, dated as of January 11, 2012, 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

01/11/2012

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.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

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. By: Chesapeake Midstream GP, L.L.C., its general partner

Date: May 10, 2012	By:	/s/ J. MIKE STICE
		J. Mike Stice
		Chief Executive Officer

Date: May 10, 2012	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

01/11/2012

4.2

8-K

001-34831

4.2

01/11/2012

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.

101.INS

XBRL Instance Document.

101.SCH

XBRL Taxonomy Extension Schema Document.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase Document.

Incorporated by Reference

Exhibit
Number

Exhibit Description

Form

SEC File
Number

Exhibit

Filing Date

Filed
Herewith

Furnished
Herewith

101.DEF

XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB

XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase Document.

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WILLIAMS PARTNERS L.P. Reports

WILLIAMS PARTNERS L.P. - FORM 10-Q - May 10, 2012

Attached files

WILLIAMS PARTNERS L.P. Reports