WILLIAMS PARTNERS L.P. - FORM 10-Q

Attached files

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EX-32.1 - SECTION 906 CERT. - CEO - WILLIAMS PARTNERS L.P.	dex321.htm
EX-32.2 - SECTION 906 CERT. - CFO - WILLIAMS PARTNERS L.P.	dex322.htm
EX-31.1 - SECTION 302 CERT. - CEO - WILLIAMS PARTNERS L.P.	dex311.htm
EX-31.2 - SECTION 302 CERT. - CFO - WILLIAMS PARTNERS L.P.	dex312.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 June 30, 2010

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

For the transition period from to

Commission File No. 1-34831

Chesapeake Midstream Partners, L.P.

(Exact Name of Registrant as Specified in Its Charter)


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


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

(405) 935-1500

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer [ ] Accelerated filer [ ] Non-accelerated filer [X] Smaller reporting company [ ]

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

As of September 7, 2010, the registrant had 69,083,265 common units outstanding.

EXPLANATORY NOTE

In September 2009, Chesapeake Energy Corporation (“Chesapeake”) and Global Infrastructure Partners – A, L.P., and affiliated funds managed by Global Infrastructure Management, L.L.C., and certain of their respective subsidiaries and affiliates (“GIP”), formed a joint venture to own and operate natural gas midstream assets. As part of the transaction, Chesapeake Midstream Development, L.P. (our “Predecessor”), a subsidiary of Chesapeake, contributed certain natural gas gathering and treating assets to a new entity, Chesapeake Midstream Partners, L.L.C. (“Successor”), and GIP purchased a 50% interest in the newly formed joint venture.

On August 3, 2010, Chesapeake Midstream Partners, L.P. (the “Partnership”) completed its initial public offering (the “Offering”) of 24,437,500 common units (such amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010), representing limited partner interests. In connection with the closing of the Offering, Chesapeake and GIP contributed Successor to the Partnership by conveying a 100% membership interest in Chesapeake MLP Operating, L.L.C., which has owned all of the Partnership’s assets since September 2009.

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

The information contained in this report relates to periods that ended prior to the completion of the Offering. Consequently, the unaudited condensed consolidated financial statements and related discussion of financial condition and results of operations contained in this report pertain to Successor and our Predecessor. The information contained in this report should be read in conjunction with the information contained in the Partnership’s prospectus dated July 28, 2010 and filed with the Securities and Exchange Commission on July 30, 2010 pursuant to Rule 424(b)(4) of the Securities Act of 1933.

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

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


PART I.
Financial Information
		Page
Item 1.	Financial Statements (Unaudited):
	Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009	1
	Condensed Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2010 and 2009	2
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2010 and 2009	3
	Condensed Consolidated Statement of Changes in Equity for the Six Months Ended June 30, 2010	4
	Notes to Condensed Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	25
Item 4.	Controls and Procedures	26

PART II.
Other Information

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)


	Successor
	June 30, 2010			December 31, 2009
	($ in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	9		$	3
Accounts receivable, including $27,789 and $165,065 from related parties at June 30, 2010 and December 31, 2009, respectively		34,379			165,771
Other current assets		3,346			1,743

Total current assets		37,734			167,517


Property, plant and equipment:
Gathering systems		2,098,336			2,013,347
Other fixed assets		35,645			34,130
Less: Accumulated depreciation		(313,002	)		(271,062	)

Total property, plant and equipment, net		1,820,979			1,776,415

Deferred loan costs, net		12,063			14,743

Total assets	$	1,870,776		$	1,958,675

LIABILITIES AND EQUITY

Current liabilities:
Accounts payable	$	31,306		$	22,940
Accrued liabilities, including $25,402 and $84,708 due to related parties at June 30, 2010 and December 31, 2009, respectively		35,721			95,158

Total current liabilities		67,027			118,098


Long-term liabilities:
Revolving bank credit facility		111,300			44,100
Other liabilities		2,965			2,850

Total long-term liabilities		114,265			46,950


Commitments and contingencies (Note 8)
Equity:
Members’ equity		1,689,484			1,793,627

Total equity		1,689,484			1,793,627

Total liabilities and equity	$	1,870,776		$	1,958,675

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Successor			Predecessor			Successor			Predecessor
	Three Months Ended June 30, 2010			Three Months Ended June 30, 2009			Six Months Ended June 30, 2010			Six Months Ended June 30, 2009
	($ in thousands)
Revenues, including revenue from affiliates (Note 6)	$	101,239		$	117,629		$	196,625		$	227,663
Operating Expenses:
Operating expenses, including expenses from affiliates (Note 7)		32,385			46,008			63,078			94,477
Depreciation and amortization expense		23,442			22,149			45,392			41,324
General and administrative expense, including expenses from affiliates (Note 7)		7,946			6,182			15,196			10,669
(Gain) loss on sale of assets		(37	)		1,364			(67	)		586

Total operating expenses		63,736			75,703			123,599			147,056

Operating income		37,503			41,926			73,026			80,607
Other Income (Expense):
Interest expense (Note 4)		(526	)		(39	)		(1,137	)		(221	)
Other income		40			16			42			18

Income before income tax expense		37,017			41,903			71,931			80,404
Income tax expense		—			(2,023	)		—			(4,271	)

Net income	$	37,017		$	39,880		$	71,931		$	76,133

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Successor			Predecessor
	Six Months Ended June 30, 2010			Six Months Ended June 30, 2009
	($ in thousands)
Cash flows from operating activities:
Net income	$	71,931		$	76,133
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		45,392			41,324
Deferred income taxes		—			4,271
(Gain) loss on sale of assets		(67	)		586
Other non-cash items		(42	)		(199	)
Changes in assets and liabilities:
Decrease in accounts receivable		130,888			13,886
Increase in other assets		(1,603	)		(104	)
Increase (decrease) in accounts payable		6,310			(96,029	)
Increase (decrease) in accrued liabilities		(55,400	)		5,664

Net cash provided by operating activities		197,409			45,532

Cash flows from investing activities:
Additions to property, plant and equipment		(97,448	)		(543,061	)
Proceeds from sale of assets		2,168			8,349

Net cash used in investing activities		(95,280	)		(534,712	)

Cash flows from financing activities:
Contributions from Chesapeake		—			570,000
Proceeds from long-term debt borrowings		233,800			634,500
Payments on long-term debt borrowings		(166,600	)		(797,300	)
Distributions to members		(169,500	)		—
Contribution from Predecessor		177			—

Net cash provided by (used in) financing activities		(102,123	)		407,200

Net increase (decrease) in cash and cash equivalents		6			(81,980	)
Cash and cash equivalents, beginning of period		3			82,025

Cash and cash equivalents, end of period	$	9		$	45

Supplemental disclosure of non-cash investing activities:
Changes in accounts payable related to purchases of property, plant and equipment	$	4,104		$	(19,801	)
Changes in other liabilities related to asset retirement obligations	$	115		$	177
Contributions of property, plant and equipment to (from) Chesapeake	$	11,705		$	(71,160	)
Supplemental disclosure of cash payments for interest	$	2,366		$	4,166

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(Unaudited)


	Members’ Equity
	($ in thousands)
Balance at December 31, 2009	$	1,793,627
Distribution to Predecessor		(6,574	)
Distributions to members		(169,500	)
Net income		71,931

Balance at June 30, 2010	$	1,689,484

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	Organization and Nature of Business

Organization

Chesapeake Midstream Development, L.P. (“CMD” or “Predecessor”) is a Delaware limited partnership formed on February 29, 2008 to own, operate and develop midstream energy assets. Upon formation, gathering and treating operations of Chesapeake Energy Marketing, Inc. (“CEMI”), a wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), were contributed to CMD. CEMI is the sole limited partner of CMD with a 98% ownership interest, and Chesapeake Midstream Management L.L.C. (“CMM”) is the general partner of CMD with a 2% ownership interest. CMM is a wholly owned subsidiary of CEMI.

Our Predecessor’s operations were conducted through the following wholly owned subsidiaries: Bluestem Gas Services, L.L.C., Texas Midstream Gas Services, L.L.C., Arkansas Midstream Gas Services Corp., AMGS, L.L.C., Louisiana Midstream Gas Services, L.L.C., Chesapeake Midstream Gas Services, L.L.C., Oklahoma Midstream Gas Services, L.L.C., Appalachia Midstream Services, L.L.C., Ponder Midstream Gas Services, L.L.C., Mid-America Midstream Gas Services, L.L.C. and Mockingbird Midstream Gas Services, L.L.C. These subsidiaries are owned by Chesapeake Midstream Operating, L.L.C., a wholly owned subsidiary of CMD.

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

Chesapeake Midstream Partners L.P. (the “Partnership”) completed its initial public offering (the “Initial Public Offering” or the “Offering”) on August 3, 2010. See Note 10 for additional information on the Offering.

Nature of Business

The Partnership is principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. The Partnership provides gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts. The assets contributed to the joint venture and ultimately the Partnership were substantially all of our Predecessor’s midstream assets in the Barnett Shale and certain of its midstream assets in the Arkoma, Anadarko, Delaware and Permian Basins. The underlying assets consist of approximately 2,900 miles of gathering pipeline, eight small hydrocarbon dew point control facilities, and two CO2/H2S extraction facilities. Subsidiaries of our Predecessor continue to operate midstream assets outside of the Successor joint venture. These include natural gas gathering assets primarily in the Fayetteville Shale, Haynesville Shale, Marcellus Shale (including other areas in the Appalachian Basin) and the Eagle Ford Shale.

2.	Basis of Presentation

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

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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

The results of operations for the three and six month periods ended June 30, 2010 are not indicative of results that may be expected for any other interim period or for the full fiscal year.

3.	Partnership Distribution

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

4.	Revolving Bank Credit Facilities

Predecessor Credit Facility

On October 16, 2008, our Predecessor closed on a revolving bank credit facility with total commitments of $460 million. All of our Predecessor’s assets were pledged as collateral under this agreement. Until its amendment and restatement effective September 30, 2009, borrowings under the credit facility bore interest at the greater of (i) the reference rate of Wells Fargo Bank, NA, (ii) the federal funds effective rate plus 0.50%, or (iii) the London Interbank Offered Rate (LIBOR) plus 1.50%. The unused portion of the credit facility was subject to a commitment fee that varied from 0.30% to 0.45%.

Our Predecessor’s credit facility agreement contained various covenants and restrictive provisions which, among other things, limited the ability of our Predecessor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. The credit facility agreement required maintenance of an indebtedness to EBITDA ratio (as defined) not to exceed 3.50 to 1, and an EBITDA (as defined) to interest expense coverage ratio of not less than 2.50 to 1. The credit facility agreement also had cross default provisions that applied to other indebtedness our Predecessor and its subsidiaries may have had with an outstanding principal amount in excess of $15 million.

Successor Credit Facility

Concurrent with the formation of Successor, as discussed in Note 1, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture’s building of additional natural gas gathering systems and for general corporate purposes. At the same time, our Predecessor amended and restated the existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under our Predecessor’s credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, our Predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. Successor capitalized $11.5 million of debt issuance costs associated with the new $500 million credit facility.

In connection with the Offering, Successor further amended its revolving credit facility. See Note 10 for additional information on the amendment to the credit facility as of August 2, 2010.

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(i) the greater of the reference rate of Wells Fargo Bank, NA, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which was subject to a margin that varied from 2.00% to 2.75% per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varied from 3.00% to 3.75% per annum according to the most recent consolidated leverage ratio. The unused portion of such credit facility was subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest was payable quarterly or, if LIBOR applied, at more frequent intervals. At June 30, 2010 and December 31, 2009, there were $111.3 million and $44.1 million, respectively, of outstanding borrowings under such credit facility.

Successor’s credit facility agreement as of June 30, 2010 required maintenance of a consolidated leverage ratio of not more than 3.50 to 1, and an interest coverage ratio (as defined) of not less than 3.00 to 1. As defined by such credit facility at June 30, 2010, the consolidated leverage ratio was 0.48 to 1 and the interest coverage ratio was 22.14 to 1.

Additionally, at June 30, 2010, such credit facility contained various covenants and restrictive provisions which, among other things, limited the ability of Successor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. If Successor failed to perform its obligations under these and other covenants, the revolving credit commitment could have been terminated and any outstanding borrowings, together with accrued interest, under the Successor credit facility could have been declared immediately due and payable. Such credit facility agreement also had cross default provisions that applied to any other indebtedness Successor had with an outstanding principal amount in excess of $15 million.

Fair Value

Estimated fair values are determined by using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts. Based on the borrowing rates available at June 30, 2010 for debt with similar terms and maturities, the carrying value of long-term debt approximates its fair value.

Capitalized Interest

For the three and six months ended June 30, 2010, interest expense was net of capitalized interest of $1.2 million and $1.5 million, respectively, for Successor, and $1.9 million and $3.8 million for the three and six month periods ended June 30, 2009, respectively, for our Predecessor.

5.	Stock-Based Compensation

Certain employees of Chesapeake have been seconded to Successor to provide operating, routine maintenance and other services with respect to the business under the direction, supervision and control of Successor. A number of these employees receive equity-based compensation through Chesapeake’s stock-based compensation programs. Chesapeake’s stock-based compensation programs consist of restricted stock issued to employees. The fair value of the awards issued is determined based on the fair market value of the shares on the date of grant. However, Successor’s restricted stock expense is allocated based on the lesser of the value at grant date or vest date. This value is amortized over the vesting period, which is generally four or five years from the date of grant. To the extent compensation cost relates to employee activities directly involved in gathering or treating operations, such amounts are charged to Successor and our Predecessor and are reflected as operating expenses. Included in operating expenses is stock-based compensation of $0.4 million and $1.0 million for Successor during the three and six month periods ended June 30, 2010, respectively, and $1.8 million and $3.5 million for our Predecessor during the three and six month periods ended June 30, 2009, respectively. To the extent compensation cost relates to employees indirectly involved in gathering or treating operations, such amounts are charged to Successor and our Predecessor through an overhead allocation and are reflected as general and administrative expenses.

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6.	Major Customers and Concentration of Credit Risk

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

CEMI accounted for $81.4 million and $163.9 million of Successor’s revenues for the three and six month periods ended June 30, 2010, respectively, and $115.4 million and $223.8 million of our Predecessor’s revenues for the three and six month periods ended June 30, 2009, respectively. Total Gas and Power North America, Inc. (“Total”) accounted for $16.4 million and $26.7 million of Successor’s revenues for the three and six months ended June 30, 2010, respectively, and accounted for none of our Predecessor’s revenues for both the three and six month periods ended June 30, 2009. Chesapeake and Total E&P USA, Inc., a wholly owned subsidiary of Total S.A., have a joint venture arrangement in which Total E&P USA, Inc. holds a 25% non-operated interest in Chesapeake’s Barnett Shale upstream assets.

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 almost exclusively 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 unaudited condensed consolidated financial statements for Successor and our Predecessor include costs allocated from Chesapeake and CEMI for centralized general and administrative services, as well as depreciation of assets utilized by Chesapeake’s centralized general and administrative functions. Prior to November 2008, allocated costs were based on identification of Chesapeake’s resources which provided a direct benefit and the proportionate share of costs based on estimated usage of shared resources and functions. Costs were allocated based on the proportionate share of Chesapeake’s headcount, compensation expense, or net revenues as appropriate for the nature of the charge. All of the allocations are based on assumptions that management believes are reasonable; however, these allocations are not necessarily indicative of the costs and expenses that would have resulted if our Predecessor had been operated as a stand-alone entity. Effective October 15, 2008, as part of the terms of the omnibus agreement, the overhead rate charged to our Predecessor became $0.02/mmbtu. Effective June 1, 2009, the allocated charges from Chesapeake were based on the actual costs for the period as opposed to the $0.02/mmbtu fee. Effective October 1, 2009, Successor was charged a general and administrative fee from Chesapeake based on the terms of the joint venture agreement. The established terms indicate corporate overhead costs are charged to Successor based on actual cost of the services provided, subject to a fee per mcf cap based on volumes of natural gas gathered. The fee is calculated as the lesser of $0.03/mcf gathered or actual corporate overhead costs. General and administrative charges were $4.5 million and $8.4 million for the three and six month periods ended June 30, 2010, respectively for Successor, and $4.7 million and $8.4 million for the three and six month periods ended June 30, 2009, respectively for our Predecessor.

Chesapeake and its affiliates also provide compression services. Monthly compressor rentals were charged to our Predecessor under short-term contracts at market rates. Successor is charged for compressor rentals based on a long-term compressor rental agreement with Chesapeake and its subsidiaries. For the three and six month periods ended June 30, 2010, compressor rental charges from affiliates were $11.5 million and $23.1 million, respectively for Successor. For the three and six month periods ended June 30, 2009, compressor rental charges from affiliates were $15.2 million and $31.0 million, respectively for our Predecessor. These charges are included in operating expenses in the accompanying unaudited condensed consolidated statements of operations.

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(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.

Our Predecessor/Successor is from time to time subject to various legal actions and claims incidental to its business, including those arising out of employment-related matters. Management believes that these routine legal proceedings will not have a material adverse effect on the financial position, results of operations or cash flows. Once it is determined that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to the estimate of the likely exposure. There was not an accrual for legal contingencies as of June 30, 2010 or December 31, 2009.

9.	Recently Issued and Proposed Accounting Standards

The Financial Accounting Standards Board (FASB) recently issued the following standards which were reviewed by management to determine the potential impact on the Partnership’s financial statements upon adoption.

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. This guidance was adopted in the first quarter of 2010.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. This guidance was adopted in the first quarter of 2010. Adoption had no impact on Successor’s financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuances and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011, and the Partnership does not expect the implementation to have a material impact on its financial position or results of operations.

10.

Subsequent Events

On August 3, 2010, the Partnership closed its Initial Public Offering of common units representing limited partner interests in the Partnership. On August 3, 2010, the Partnership had outstanding 69,076,122 common units, 69,076,122 subordinated units, a 2% general partner interest and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as the Partnership’s per-unit cash distributions increase above specified levels. The common units are listed on the New York Stock Exchange under the symbol “CHKM”.

A summary of the key Offering transactions follows:

•

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

•

The Partnership received gross offering proceeds of approximately $513.2 million from the issuance and sale of 24,437,500 common units (such amount includes 3,187,500 common units issued pursuant to the exercise of the underwriters’ over-allotment option on August 3, 2010) at an initial offering price of $21.00 per unit less approximately $38.1 million for underwriting discounts and commissions, structuring fees and offering expenses. Pursuant to the terms of the contribution agreement, the Partnership distributed the approximate $62.4 million of net proceeds from the exercise of the over-allotment option to GIP on August 3, 2010. Common units held by public security holders represent 17.7% of all outstanding limited partner interests, and

CHESAPEAKE MIDSTREAM PARTNERS, L.L.C. AND

CHESAPEAKE MIDSTREAM DEVELOPMENT, L.P.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Chesapeake and GIP hold 42.3% and 40.0%, respectively, of all outstanding limited partner interests. The limited partners, collectively, hold a 98.0% limited partner interest in the Partnership and the general partner, which is owned and controlled by Chesapeake and GIP, holds a 2.0% general partner interest in the Partnership.

•

The Partnership used the net offering proceeds (excluding the distribution to GIP) to repay approximately $110.0 million of borrowings under its revolving credit facility and to pay approximately $5.5 million of fees related to the amendment of its revolving credit facility. Approximately $223.5 million of the net proceeds was retained to fund identified expansion capital expenditures (see definition of expansion capital expenditures under the heading “Capital Requirements” in Part I, Items 2 of this Form 10-Q) during the twelve months ended June 30, 2011, and the remainder is expected to be used for additional capital expenditures in future periods.

In connection with the Offering, Successor amended its revolving bank credit facility, which will now mature in June 2015. As amended, the Successor credit facility provides up to $750 million of borrowing capacity and includes a sub-limit up to $25 million for same-day swing line advances and a sub-limit up to $50 million for letters of credit. In addition, the Successor credit facility contains an accordion feature that allows Successor to increase the available borrowing capacity under the facility up to $1 billion, subject to the satisfaction of certain closing conditions, including the identification of lenders or proposed lenders that agree to satisfy the increased commitment amounts under the facility. Borrowings under the Successor credit facility are secured by all of the assets of Successor, and loans thereunder (other than swing line loans) bear interest at Successor’s option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which is subject to a margin that varies from 1.75% to 2.25% per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varies from 2.75% to 3.25% per annum according to the most recent consolidated leverage ratio. The unused portion of the Successor credit facility is subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio.

The amended Successor credit facility agreement requires maintenance of a consolidated leverage ratio of not more than 4.50 to 1 and an interest coverage ratio (as defined) of not less than 3.00 to 1.

ITEM 2.

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

The historical unaudited condensed consolidated financial statements reflect the assets, liabilities and operations of our Predecessor (for periods ending on or before September 30, 2009) and of the successor to our Predecessor, which we refer to as Successor (for periods ending after September 30, 2009). On September 30, 2009, Chesapeake and GIP formed Successor in a joint venture transaction to own and operate a portion of the business of our Predecessor consisting of certain assets and operations that have historically been engaged in gathering, treating and compressing natural gas for Chesapeake and its working interest partners. Our Predecessor retained a 50% interest in Successor and continues to operate midstream assets outside of Successor. On August 3, 2010, Chesapeake and GIP contributed Successor to the Partnership by conveying a 100% membership interest in Chesapeake MLP Operating, L.L.C. to the Partnership. On this date, the Partnership also closed its initial public offering (“the Offering”) of common units representing limited partner interests.

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

Overview

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


	Three Months Ended June 30, 2010			Six Months Ended June 30, 2010
	(In thousands, except operational data)
Revenues⁽¹⁾	$	101,239		$	196,625

Operating expenses		32,385			63,078
Depreciation and amortization expense		23,442			45,392
General and administrative expense		7,946			15,196
Gain on sale of assets		(37	)		(67	)

Total operating expenses		63,736			123,599

Operating income		37,503			73,026
Interest expense		(526	)		(1,137	)
Other income		40			42

Income before income tax expense		37,017			71,931
Income tax expense		—			—

Net income	$	37,017		$	71,931

Key Performance Metrics:
Adjusted EBITDA⁽²⁾	$	60,948		$	118,393
Distributable Cash Flow⁽²⁾	$	42,922		$	82,256
Operational Data:
Wells connected during period		96			180
Throughput, mmcf per day		1,624			1,577
Miles of pipe at end of period		2,900			2,900
Gas compression (horsepower) at end of period		221,020			221,020

(1)

In the event either Chesapeake or Total does not meet its minimum volume commitment to us in our Barnett Shale Region under our gas gathering agreements, as adjusted in certain circumstances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. Should payments be due under the minimum volume commitment with respect to any year, we recognize the associated revenue in the fourth quarter of that year.

(2)

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

We are a limited partnership formed to own, operate, develop and acquire natural gas gathering systems and other midstream energy assets. We are principally focused on natural gas gathering, the first segment of midstream energy infrastructure that connects natural gas produced at the wellhead to third-party takeaway pipelines. We provide gathering, treating and compression services to Chesapeake and Total, our primary customers, and other third-party producers under long-term, fixed-fee contracts.

Our gathering systems operate in our Barnett Shale region in north-central Texas and our Mid-Continent region, which includes the Anadarko, Arkoma, Delaware and Permian Basins. We generate the majority of our operating income in our Barnett Shale region, where we service approximately 1,700 wells in the core of the Barnett Shale. In our Mid-Continent region, we have an enhanced focus on the unconventional resources located in the Colony Granite Wash and Texas Panhandle Granite Wash plays of the Anadarko Basin. Our systems consist of approximately 2,900 miles of gathering pipelines, servicing approximately 4,000 natural gas wells. For both the Current Quarter and Current Period, our assets gathered approximately 1.6 bcf of natural gas per day.

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

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

Our Gas Gathering Agreements

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

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

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

•

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

•

Acreage Dedication. Pursuant to our gas gathering agreements, subject to certain exceptions, each of Chesapeake and Total has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on natural gas and oil leases covering lands within an acreage dedication in our Barnett Shale region.

•

Minimum Volume Commitments. Pursuant to our gas gathering agreements, Chesapeake and Total have agreed to minimum volume commitments for each year through December 31, 2018 and for the six-month period ending June 30, 2019. Approximately 75% of the aggregate minimum volume commitment will be attributed to Chesapeake, and approximately 25% will be attributed to Total. The minimum volume commitments increase, on average, approximately 3% per year. In the event either Chesapeake or Total does not meet its minimum volume commitment to us, as adjusted in certain instances, for any annual period (or six-month period in the case of the six months ending June 30, 2019) during the minimum volume commitment period, Chesapeake or Total, as applicable, will be obligated to pay us a fee equal to the Barnett Shale fee for each mcf by which the applicable party’s minimum volume commitment for the year (or six-month period) exceeds the actual volumes gathered on our systems attributable to the applicable party’s production. To the extent natural gas gathered on our systems from Chesapeake or Total, as applicable, during any annual period (or six-month period) exceeds such party’s minimum volume commitment for the period, Chesapeake or Total, as applicable, will be obligated to pay us the Barnett Shale fee for all volumes gathered, and the excess volumes will be credited first against the minimum volume commitments for the six months ending June 30, 2019, and then against the minimum volume commitments of each preceding year. In the event that the minimum volume commitment for any period is credited in full, the minimum volume commitment period will be shortened to end on the final day of the immediately preceding period.

•

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

•

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

•

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

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

•

Gathering, Treating and Compression Services. We gather, treat and compress natural gas in exchange for system-based services fees per mcf for natural gas gathered and per mcf for natural gas compressed, which we refer to as the Mid-Continent fees. The Mid-Continent fees for these systems are subject to an annual 2.5% rate escalation at the beginning of each year.

•

Acreage Dedication. Pursuant to our gas gathering agreement, subject to certain exceptions, Chesapeake has agreed to dedicate all of the natural gas owned or controlled by it and produced from or attributable to existing and future wells located on oil, natural gas and mineral leases covering lands within the acreage dedication.

•

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

•

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

•

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

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

Other Arrangements

Business Opportunities. Pursuant to our omnibus agreement, Chesapeake has agreed to provide us a right of first offer with respect to three specified categories of transactions: (i) opportunities to develop or invest in midstream energy projects within five miles of our acreage dedications, (ii) opportunities to succeed third parties in expiring midstream energy service contracts within five miles of the acreage dedications, and (iii) opportunities with respect to future midstream divestitures outside of the acreage dedications. The consummation, if any, and timing of any such future transactions will depend upon, among other things, our ability to reach an agreement with Chesapeake and our ability to

obtain financing on acceptable terms. Notwithstanding the foregoing, Chesapeake is under no obligation to accept any offer made by us with respect to such opportunities. Although we will have certain rights with respect to the potential business opportunities, we are not under any contractual obligation to pursue any such transactions.

Services Arrangements. Under the services agreement, Chesapeake has agreed to provide us with certain general and administrative services and any additional services we may request. We will reimburse Chesapeake for such general and administrative services in any given month subject to a cap equal to $0.03 per mcf multiplied by the volume (measured in mcf) of natural gas that we gather, treat or compress. The $0.03 per mcf cap will be subject to an annual upward adjustment on October 1 of each year equal to 50% of any increase in the Consumer Price Index, and, subject to receipt of requisite approvals, such cap may be further adjusted to reflect changes in general and administrative services provided by Chesapeake relating to new laws or accounting rules that are implemented. The cap contained in the services agreement does not apply to our direct general and administrative expenses and may not apply to certain of the incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership.

Additionally, pursuant to an employee secondment agreement, specified employees of Chesapeake will be seconded to our general partner to provide operating, routine maintenance and other services with respect to our business under the direction, supervision and control of our general partner. Our general partner will, subject to specified exceptions and limitations, reimburse Chesapeake on a monthly basis for substantially all costs and expenses it incurs relating to such seconded employees. Additionally, under our employee transfer agreement, we will be required to maintain certain compensation standards for seconded employees to whom we make offers for hire.

How We Evaluate Our Operations

Our results are driven primarily by our customers’ minimum volume commitments and the actual volumes of natural gas we gather, treat and compress. In the case of our Barnett Shale volumes, our results will be supported by the minimum volume commitments contained in our gas gathering agreements with Chesapeake and Total. We contract with producers to gather natural gas from individual wells located near our gathering systems. We connect wells to gathering pipelines through which natural gas is compressed and may be delivered to a treating facility, processing plant or an intrastate or interstate pipeline for delivery to market. We treat natural gas that we gather to the extent necessary to meet required specifications of third-party takeaway pipelines. For the Current Quarter and Current Period, Chesapeake and its working interest partners accounted for approximately 92% and 93%, respectively, of the natural gas volumes on our gathering systems and 96% and 97%, respectively, of our revenues.

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

Throughput Volumes

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

Operating Expenses

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

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

Adjusted EBITDA and Distributable Cash Flow

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

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

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

•

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

•

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

•

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

•

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

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

Items Impacting the Comparability of Our Financial Results

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

•

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

•

The historical consolidated financial statements of our Predecessor cover periods in which our assets experienced significant growth. Due to the significant build-out of our gathering systems, capital expenditures by our Predecessor for historical periods presented in the unaudited condensed consolidated financial statements in Part I, Item I of this Form 10-Q were higher than those we anticipate we will experience in future periods.

•

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

•

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

•

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

•

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

•

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

•

Following the Offering, we intend to make cash distributions to our unitholders and our general partner at an initial distribution rate of $0.3375 per unit per quarter ($1.35 per unit on an annualized basis). We expect to declare and pay a prorated distribution following the quarter ending September 30, 2010, covering the period from the closing of our initial public offering through September 30, 2010. Based on the terms of our cash distribution policy, we expect that we will distribute to our unitholders and our general partner most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our amended revolving credit facility and future issuances of equity and debt securities. Historically, our Predecessor largely relied on internally generated cash flows and capital contributions from Chesapeake to satisfy its capital expenditure requirements.

Results of Operations – Three Months Ended June 30, 2010

Revenues. Successor’s revenues are primarily attributable to the amount of throughput on its gathering systems and the rates charged for gathering such throughput. During the Current Quarter, revenues were $101.2 million compared to $95.4 million during the three months ended March 31, 2010. In the Current Quarter, throughput was 1,624 mmcf per day compared to 1,530 mmcf per day during the three months ended March 31, 2010. Successor connected 96 wells during the Current Quarter.

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


	Revenues		Throughput (bcf)
	(In thousands, except operational data)
Barnett Shale	$	75,940		96.4
Mid-Continent		25,299		51.4

	$	101,239		147.8


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

	Operating Expenses		Expenses ($ per mcf)
	(In thousands, except per mcf data)
Barnett Shale	$	20,472	$	0.21
Mid-Continent		11,913		0.23

	$	32,385	$	0.22

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

General and Administrative Expense. During the Current Quarter, general and administrative expenses were $7.9 million compared to $7.3 million during the three months ended March 31, 2010, and were primarily attributable to the expansion of Successor’s senior management team and the ongoing expansion of general and administrative functions of Successor, specifically in preparation for the functions required by our status as a public company following the Offering.

Interest Expense. Interest expense for the Current Quarter was $0.5 million which was net of $1.2 million of capitalized interest. Interest expense is related to borrowings under our revolving credit facility.

Income Tax Expense. There was no income tax expense during the Current Quarter. Successor and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the unaudited condensed consolidated financial statements.

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


	Three Months Ended
	June 30, 2010
	($ in thousands)
Net Income	$	37,017
Interest expense		526
Depreciation and amortization expense		23,442
(Gain) Loss on sale of assets		(37	)

Adjusted EBITDA	$	60,948


Cash Provided By Operating Activities	$	79,084
Changes in assets and liabilities		(18,688	)
Maintenance capital expenditures		(17,500	)
Other non-cash items		26

Distributable Cash Flow	$	42,922

Results of Operations – Six Months Ended June 30, 2010

Revenues. During the Current Period, Successor throughput was 1,577 mmcf per day resulting in revenues of $196.6 million. Successor connected 180 wells during the Current Period.

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


	Revenues		Throughput (bcf)
	(In thousands, except operational data)
Barnett Shale	$	147,540		184.5
Mid-Continent		49,085		101.0

	$	196,625		285.5


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

	Operating Expenses		Expenses ($ per mcf)
	(In thousands, except per mcf data)
Barnett Shale	$	39,437	$	0.21
Mid-Continent		23,641		0.23

	$	63,078	$	0.22

Depreciation and Amortization Expense. Depreciation and amortization expense for the Current Period was $45.4 million and primarily related to gathering systems.

General and Administrative Expense. During the Current Period, general and administrative expenses were $15.2 million and were primarily attributable to the expansion of Successor’s senior management team and the ongoing expansion of general and administrative functions of Successor.

Interest Expense. Interest expense for the Current Period was $1.1 million which was net of $1.5 million of capitalized interest. Interest expense is related to borrowings under our revolving credit facility.

Income Tax Expense. There was no income tax expense during the Current Period. Successor and its subsidiaries are pass-through entities for federal income tax purposes. For these entities, all income, expenses, gains, losses and tax credits generated flow through to their owners and, accordingly, do not result in a provision for income taxes in the unaudited condensed consolidated financial statements.

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


	Six Months Ended June 30, 2010
	($ in thousands)
Net Income	$	71,931
Interest expense		1,137
Depreciation and amortization expense		45,392
(Gain) Loss on sale of assets		(67	)

Adjusted EBITDA	$	118,393


Cash Provided By Operating Activities	$	197,409

Changes in assets and liabilities		(80,195	)
Maintenance capital expenditures		(35,000	)
Other non-cash items		42

Distributable Cash Flow	$	82,256

Liquidity and Capital Resources

Our ability to finance operations and fund capital expenditures will largely depend on our ability to generate sufficient cash flow to cover these expenses. Our ability to generate cash flow is subject to a number of factors, some of which are beyond our control. See Risk Factors in our prospectus dated July 28, 2010 and filed with the SEC on July 30, 2010.

Historically, Successor’s sources of liquidity included cash generated from operations and borrowings under Successor’s revolving credit facility.

Working Capital (Deficit). Working capital, defined as the amount by which current assets exceed current liabilities, is an indication of liquidity and the potential need for short-term funding. As of December 31, 2009 and June 30, 2010, Successor had working capital (deficit) of $49.4 million and $(29.3) million, respectively. Successor’s working capital decreased from December 31, 2009 to June 30, 2010 as a result of distributions to members partially offset by borrowings under Successor’s credit facility.

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


	Six Months Ended June 30, 2010
	($ in thousands)
Cash Flow Data:
Net cash provided by (used in):
Operating activities	$	197,409
Investing activities	$	(95,280	)
Financing activities	$	(102,123	)

Operating Activities. Net cash provided by operating activities was $197.4 million for the Current Period. This amount was attributable to both cash flow from operations and changes in working capital. Cash from operations has increased as additional volumes are brought onto our systems. Working capital is positive as a result of settlement of December 31, 2009 accounts receivable and accrued liabilities with Chesapeake in connection with the post-closing requirements of the purchase agreement relating to the joint venture transaction between Chesapeake and GIP.

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

Financing Activities. Net cash used in financing activities was $102.1 million for the Current Period, resulting primarily from $169.5 million of distributions to members and net proceeds of $67.2 million from the revolving credit facility.

Sources of Liquidity

Following the Offering, we expect our sources of liquidity to include:

•

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

•

cash generated from operations;

•

borrowings under our revolving credit facility; and

•

future issuances of equity and debt securities.

We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to fund our quarterly cash distributions to unitholders.

Successor Credit Facility

Concurrent with the formation of Successor, the newly created joint venture closed a new $500 million secured revolving bank credit facility to fund capital expenditures associated with the joint venture’s building of additional natural gas gathering systems and for general corporate purposes. At the same time, our Predecessor amended and restated the existing revolving bank credit facility to reduce its capacity from $460 million to $250 million, among other changes. The outstanding balance under the credit facility was repaid at the time of the amendment. In conjunction with the establishment of the new facilities, our Predecessor expensed $4 million of previously capitalized debt issuance costs associated with this amendment and capitalized $5.7 million associated with the amended $250 million credit facility. Successor capitalized $11.5 million of debt issuance costs associated with the new $500 million credit facility.

Successor’s revolving bank credit facility as of June 30, 2010 would have matured in September 2012. Borrowings under such credit facility were secured by all of the assets of Successor, and bore interest at Successor’s option at either (i) the greater of the reference rate of Wells Fargo Bank, NA, the federal funds effective rate plus 0.50%, and the one-month LIBOR plus 1.00%, all of which was subject to a margin that varied from 2.00% to 2.75% per annum according to the most recent consolidated leverage ratio (as defined) or (ii) the LIBOR plus a margin that varied from 3.00% to 3.75% per annum according to the most recent consolidated leverage ratio. The unused portion of such credit facility was subject to a commitment fee of 0.50% per annum according to the most recent consolidated leverage ratio. Interest was payable quarterly or, if LIBOR applied, at more frequent intervals. At June 30, 2010 and December 31, 2009, there were $111.3 million and $44.1 million, respectively, of outstanding borrowings under such credit facility.

Additionally, such credit facility contained various covenants and restrictive provisions which, among other things, limited the ability of Successor and its subsidiaries to incur additional indebtedness, make investments or loans, create liens and pay dividends or distributions. If Successor failed to perform its obligations under these and other covenants, the revolving credit commitment could have been terminated and any outstanding borrowings, together with accrued interest, under the Successor credit facility could have been declared immediately due and payable. Such credit facility agreement also had cross default provisions that applied to any other indebtedness Successor had with an outstanding principal amount in excess of $15 million.

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

•

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

•

expansion capital expenditures, which include those expenditures incurred in order to acquire additional assets to grow our business, expand and upgrade our systems and facilities, extend the useful lives of our assets, increase gathering, treating and compression throughput from current levels and reduce costs or increase revenues.

For the Current Period, expansion capital expenditures totaled $62.4 million and management’s estimate of maintenance capital expenditures totaled $35.0 million. Our 2010 year-to-date spending and budgeted capital expenditures for the remainder of 2010 are primarily concentrated in our Barnett Shale region and in the Colony Granite Wash and Texas Panhandle Granite Wash plays in our Mid-Continent region. Our future capital expenditures may vary significantly from budgeted amounts and from period to period based on the investment opportunities that become available to us.

We continually review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Because our partnership agreement requires us to distribute all of our available cash to our unitholders, we expect to fund future capital expenditures from cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities.

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

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. requires us and our Predecessor to make estimates and assumptions that affect the reported amounts and disclosure of contingencies. We and our Predecessor make significant estimates which impact depreciation and assumptions regarding future net cash flows. Although we and our Predecessor believe these estimates are reasonable, actual results could differ from our estimates.

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

Recently Issued and Proposed Accounting Standards

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

In February 2010, the FASB amended its guidance on subsequent events to remove the requirement for SEC filers to disclose the date through which an entity has evaluated subsequent events. The guidance was effective upon issuance. We adopted this guidance in the first quarter of 2010.

The FASB also issued new guidance requiring additional disclosures about fair value measurements, adding a new requirement to disclose transfers in and out of Levels 1 and 2 measurements and gross presentation of activity within a Level 3 roll forward. The guidance also clarified existing disclosure requirements regarding the level of disaggregation of fair value measurements and disclosures regarding inputs and valuation techniques. We adopted this guidance in the first quarter of 2010. Adoption had no impact on our financial position or results of operations. Required disclosures for the reconciliation of purchases, sales, issuance and settlements of financial instruments valued with a Level 3 method are effective beginning on January 1, 2011 and we do not expect the implementation to have a material impact on our financial position or results of operations.

Forward-Looking Statements

Certain statements and information in this Quarterly Report on Form 10-Q may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

competitive conditions;

•

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

•

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

•

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

•

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

•

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

•

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

•

our lack of industry and geographic diversification; and

•

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

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

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

ITEM 3.

Quantitative and Qualitative Disclosures About Market Risk

We are dependent on Chesapeake and Total for substantially all of our supply of natural gas volumes and are consequently subject to the risk of nonpayment or late payment by Chesapeake and Total of gathering, treating and compression fees, as applicable. Chesapeake’s debt ratings for its senior notes are below investment grade, and they may remain below investment grade for the foreseeable future. Additionally, neither of our Total counterparties under our gas gathering agreement, nor the Total guarantor of those counterparties, is rated by credit rating agencies. Accordingly, this risk may be more difficult to evaluate than it would be with an investment grade or otherwise rated contract counterparty or with a more diversified group of customers, and unless and until we significantly increase our customer base, we expect to continue to be subject to significant and non-diversified risk of nonpayment or late payment of our fees.

Interest Rate Risk

Interest rates have recently experienced near record lows. If interest rates rise, our financing costs would increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect in this regard to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Commodity Price Risk

We attempt to mitigate commodity price risk by contracting our operations on a long-term fixed-fee basis and through various provisions in our gas gathering agreements with Chesapeake and Total that are intended to support the stability of our cash flows. Natural gas prices are historically impacted by changes in the supply and demand of natural gas, as well as market uncertainty. However, an actual or anticipated prolonged reduction in natural gas prices could result in reduced drilling in our areas of operations and, accordingly, in volumes of natural gas gathered by our systems. Notwithstanding the minimum volume commitments of Chesapeake and Total in our Barnett Shale region and the fee redetermination provisions under our gas gathering agreements, a reduction in volumes of natural gas gathered by our systems could adversely affect both our profitability and our cash flows. Adverse effects on our cash flows from reductions in natural gas prices could adversely affect our ability to make cash distributions to our unitholders.

We have agreed to negotiate with Chesapeake to establish a mutually acceptable volumetric-based cap on fuel, lost and unaccounted for gas and electricity on our systems with respect to its volumes. Although we have not yet agreed on a cap with Chesapeake, to the extent we were to exceed an agreed cap in the future, we may incur significant expenses to replace the volume of natural gas used as fuel, or lost or unaccounted for, and electricity, in excess of such cap based on the then current natural gas prices. Accordingly, this replacement obligation may subject us to direct commodity price risk.

Additionally, an increase in commodity prices could result in increased costs of steel and other products that we use in the operation of our business, as well as the cost of obtaining rights-of-way for property on which our assets are located. Accordingly, our operating expenses and capital expenditures could increase as a result of an increase in commodity prices.

ITEM 4.

Controls and Procedures

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

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

PART II. OTHER INFORMATION

ITEM 1.

Legal Proceedings

We are not party to any legal proceeding other than legal proceedings arising in the ordinary course of our business. We are a party to various administrative and regulatory proceedings that have arisen in the ordinary course of our business. Management believes that there are no such proceedings for which final disposition could have a material adverse effect on our results of operations, cash flows or financial position.

ITEM 1A.

Risk Factors

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

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

ITEM 3.

Defaults Upon Senior Securities

Not applicable.

ITEM 4.

(Removed and Reserved)

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.

8-K

001-34831

3.1

08/05/2010

31.1

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

31.2

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

32.1

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

32.2

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

SIGNATURES

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


	CHESAPEAKE MIDSTREAM PARTNERS, L.P.

Date: September 13, 2010	By:	/s/ J. MIKE STICE
		J. Mike Stice Chief Executive Officer

Date: September 13, 2010	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.

8-K

001-34831

3.1

08/05/2010

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.

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