Crestwood Midstream Partners 10Q 2012 Q1 Quarterly report

Crestwood Midstream Partners Inactive 10-Q2012 Q1 Quarterly report

Content analysis

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-33631

Crestwood Midstream Partners LP

(Exact name of registrant as specified in its charter)


Delaware		56-2639586
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

717 Texas Avenue, Suite 3150, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(832) 519-2200

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report)

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 þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ 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.

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

Indicate the number of shares outstanding of the issuer’s common units and Class C units, as of the latest practicable date:


Title of Class		Outstanding as of April 30, 2012
Common Units		36,538,228
Class C Units		6,716,730

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO FORM 10-Q

For the Period Ended March 31, 2012


PART I. FINANCIAL INFORMATION		4

Item 1.	Financial Statements (Unaudited)	4

	Condensed Consolidated Statements of Income for the three months ended March 31, 2012 and 2011	4

	Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011	5

	Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2012 and 2011	6

	Condensed Consolidated Statements of Changes in Partners’ Capital for the three months ended March 31, 2012 and 2011	7

	Notes to Condensed Consolidated Financial Statements	8

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Item 4.	Controls and Procedures	31

PART II. OTHER INFORMATION		32

Item 1.	Legal Proceedings	32

Item 1A.	Risk Factors	32

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	33

Item 3.	Defaults Upon Senior Securities	33

Item 4.	Mine Safety Disclosures	33

Item 5.	Other Information	33

Item 6.	Exhibits	34

Signatures		35
Certification(s) Pursuant to Section 302
Certification Pursuant to Section 906

FORWARD-LOOKING INFORMATION

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (“SEC”), or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “plan,” “aim,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed.

Important factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to, the following risks and uncertainties:

•

changes in general economic conditions;

•

fluctuations in oil, natural gas and natural gas liquids prices;

•

the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of our assets;

•

failure or delays by our customers in achieving expected production in their natural gas projects;

•

competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and processing assets or systems;

•

actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

•

our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;

•

changes in the availability and cost of capital;

•

operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

•

timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

•

the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

•

the effects of existing and future litigation;

•

risks related to our substantial indebtedness; and

•

certain factors discussed elsewhere in this report.

These factors do not necessarily include all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to, or effect on, us or our business or operations. Also note that we provided additional cautionary discussion of risks and uncertainties in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2011.

Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except for per unit data - Unaudited)


	Three Months Ended March 31,
	2012		2011
Revenue
Gathering revenue - related party	$	23,846	$	23,351
Gathering revenue		11,837		1,476
Processing revenue - related party		6,771		6,637
Processing revenue		1,196		516
Product sales		10,083		400

Total revenue		53,733		32,380

Expenses
Operations and maintenance		9,711		7,381
Product purchases		8,973		—
General and administrative		6,738		6,370
Depreciation, amortization and accretion		10,646		6,025

Total expenses		36,068		19,776

Operating income		17,665		12,604
Interest expense		7,557		3,006

Income from operations before income taxes		10,108		9,598
Income tax provision		303		222

Net income	$	9,805	$	9,376

General partner’s interest in net income	$	3,368	$	888
Limited partners’ interest in net income	$	6,437	$	8,488
Basic income per unit:
Net income per limited partner unit	$	0.15	$	0.27
Diluted income per unit:
Net income per limited partner unit	$	0.15	$	0.27

Weighted-average number of limited partner units:
Basic		42,694		31,188
Diluted		42,877		31,324
Distributions declared per limited partner unit (attributable to the period ended)	$	0.50	$	0.44

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data - Unaudited)


	March 31, 2012		December 31, 2011
ASSETS
Current assets
Cash and cash equivalents	$	814	$	797
Accounts receivable		14,037		11,926
Accounts receivable - related party		23,220		27,312
Prepaid expenses and other		1,204		1,935

Total current assets		39,275		41,970
Investment in unconsolidated affiliate		131,250		—
Property, plant and equipment, net		749,816		746,045
Intangible assets, net		126,097		127,760
Goodwill		93,628		93,628
Deferred financing costs, net		15,467		16,699
Other assets		806		790

Total assets	$	1,156,339	$	1,026,892

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable, accrued expenses and other	$	28,619	$	31,794
Accrued additions to property, plant and equipment		6,932		7,500
Accounts payable - related party		1,764		1,308
Capital leases		2,714		2,693

Total current liabilities		40,029		43,295
Long-term debt		553,250		512,500
Long-term capital leases		3,242		3,929
Asset retirement obligations		11,978		11,545
Commitments and contingent liabilities (Note 12)
Partners’ capital
Common unitholders (36,538,228 and 32,997,696 units issued and outstanding at March 31, 2012 and December 31, 2011, respectively)		377,620		286,945
Class C unitholders (6,716,730 and 6,596,635 units issued and outstanding at March 31, 2012 and December 31, 2011, respectively)		158,386		157,386
General partner		11,834		11,292

Total partners’ capital		547,840		455,623

	$	1,156,339	$	1,026,892

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands – Unaudited)


	Three Months Ended March 31,
	2012			2011
Operating activities:
Net income	$	9,805		$	9,376
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		10,482			5,890
Accretion of asset retirement obligations		164			135
Equity-based compensation		493			283
Amortization of deferred financing fees and debt issuance costs		1,302			678
Changes in assets and liabilities:
Accounts receivable		(2,111	)		296
Prepaid expenses and other		715			468
Accounts receivable - related party		4,092			(6,174	)
Accounts payable - related party		456			313
Accounts payable, accrued expenses and other		(3,245	)		6,097

Net cash provided by operating activities		22,153			17,362

Investing activities:
Capital expenditures		(12,889	)		(13,076	)
Investment in unconsolidated affiliate		(131,250	)		—

Net cash (used in) investing activities		(144,139	)		(13,076	)

Financing activities:
Proceeds from credit facility		182,000			38,400
Repayments of credit facility		(141,250	)		(29,104	)
Payments on capital leases		(666	)		—
Proceeds from issuance of Class C units		—			12,250
Proceeds from issuance of common units, net		103,050			—
Distributions to partners		(20,729	)		(14,288	)
Taxes paid for equity-based compensation vesting		(402	)		—

Net cash provided by financing activities		122,003			7,258

Net cash increase		17			11,544
Cash and cash equivalents at beginning of period		797			2

Cash and cash equivalents at end of period	$	814		$	11,546

Cash paid for interest	$	2,561		$	2,388
Non-cash transactions:
Working capital related to capital expenditures	$	6,932		$	4,209
Paid-In-Kind value to Class C unitholders	$	3,666		$	—

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands – Unaudited)


	Partners’ Capital
	Limited Partners
	Common			Class C Unitholders		General Partner			Total
Balance at December 31, 2011	$	286,945		$	157,386	$	11,292		$	455,623
Equity-based compensation		493			—		—			493
Taxes paid for equity-based compensation vesting		(402	)		—		—			(402	)
Distributions paid		(17,903	)		—		(2,826	)		(20,729	)
Net income		5,437			1,000		3,368			9,805
Issuance of units, net of offering costs		103,050			—		—			103,050

Balance at March 31, 2012	$	377,620		$	158,386	$	11,834		$	547,840


	Partners’ Capital
	Limited Partners
	Common			Class C Unitholders		General Partner			Total
Balance at December 31, 2010	$	258,069		$	—	$	684		$	258,753
Equity-based compensation		283			—		—			283
Distributions paid		(13,411	)		—		(877	)		(14,288	)
Net income		8,488			—		888			9,376

Balance at March 31, 2011	$	253,429		$	—	$	695		$	254,124

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

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

UNAUDITED

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization— Crestwood Midstream Partners LP (“CMLP”) is a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. Crestwood Gas Services GP LLC, our general partner (“General Partner”), is owned by Crestwood Holdings Partners, LLC and its affiliates (“Crestwood Holdings”). Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “CMLP.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of CMLP and its subsidiaries.

Organizational Structure

The following chart depicts our ownership structure as of March 31, 2012:

LOGO

Our ownership is as follows:


	March 31, 2012
	Crestwood Holdings			Public			Total
General partner interest		1.7	%		—			1.7	%
Limited partner interest
Common unitholders		44.4	%		38.6	%		83.0	%
Class C unitholders		0.1	%		15.2	%		15.3	%

Total		46.2	%		53.8	%		100.0	%

See Note 16 — “Partners’ Capital and Distributions” for additional information concerning ownership interests.

Description of Business— We are primarily engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of natural gas liquids (“NGLs”) produced in the geological formations of the Barnett Shale in north Texas, the Avalon Shale area of southeastern New Mexico, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Haynesville/Bossier Shale in western Louisiana and the Marcellus Shale in West Virginia.

On March 26, 2012, we invested $131 million for a 35% interest in Crestwood Marcellus Midstream LLC (“CMM”) which is held by our wholly-owned subsidiary. Crestwood Holdings LLC, invested an additional $244 million for the remaining 65% interest which is held by its wholly-owned subsidiary. CMM is a new joint venture formed for the purpose of acquiring certain of Antero Resources Appalachian Corporation’s (“Antero”) Marcellus Shale gathering system assets located in Harrison and Doddridge Counties, West Virginia. CMM’s purchase price to acquire the assets was $375 million, subject to normal purchase price adjustments, in cash, plus an earn-out which would allow Antero to earn additional purchase price payments of up to $40 million based upon average annual production levels achieved during 2012 and 2013.

Additionally, CMM entered into a 20-year, fixed fee, gas gathering and compression agreement with Antero, which will provide for an area of dedication of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. As part of the gas gathering and compression agreement, Antero committed to delivery of minimum annual volumes to CMM for a seven year period from 2012-2019, resulting in total guaranteed volume commitments over the seven year period to CMM of approximately 300 million cubic feet per day (“MMcfd”) to 450 MMcfd.

The assets acquired by CMM include 33 miles of low pressure gathering pipelines gathering approximately 210 MMcfd at closing from 59 existing horizontal Marcellus Shale wells. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion and Equitrans.

Approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fee-based service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows. We have four systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System, part of the Barnett segment, (ii) the Granite Wash System, (iii) and the two systems acquired by CMM in the Marcellus segment. For the three months ended March 31, 2012, our systems located in NGL rich basins or rich gas shale plays contributed approximately 51% of our total revenue. (See Note 4 — “Investment in Unconsolidated Affiliate” and Note 18— “Segment Information”)

See Note 1 to the consolidated financial statements in our 2011 Annual Report on Form 10-K for additional information about our business.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation— We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the SEC. As an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles (“GAAP”) and should be read along with our 2011 Annual Report on Form 10-K. The financial statements as of March 31, 2012, and for the three months ended March 31, 2012 and 2011, are unaudited. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Our disclosures in this Form 10-Q are an update to those provided in our 2011 Annual Report on Form 10-K.

Significant Accounting Policies

There were no changes in the significant accounting policies described in our 2011 Annual Report on Form 10-K, except as noted below.

Principles of Consolidation — We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We currently do not have ownership in any variable interest entities. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of the entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Segment Information— We conduct all of our operations in the midstream sector with eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. All of our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States.

Recently Issued Accounting Standards

Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. There have been no new or revised accounting standards that are applicable to us since December 31, 2011.

See Note 2 to the consolidated financial statements in our 2011 Annual Report on Form 10-K for additional information regarding recent issued accounting standards.

3. ACQUISITIONS

2011 Acquisitions

Las Animas Acquisition

On February 16, 2011, we completed the acquisition of certain midstream assets in the Avalon Shale play from a group of independent producers for $5.1 million (“Las Animas Acquisition”).

The Las Animas Acquisition was recorded in property, plant and equipment at fair value of $5.1 million.

Frontier Gas Acquisition

On April 1, 2011, we completed the acquisition of certain midstream assets in the Fayetteville Shale and the Granite Wash from Frontier Gas Services, LLC for approximately $345 million (“Frontier Gas Acquisition”). In third quarter 2011, we finalized the Frontier Gas Acquisition purchase price, which resulted in the recognition of approximately $93.6 million in goodwill.

Tristate Acquisition

On November 1, 2011, we acquired Tristate Sabine, LLC (“Tristate”) from affiliates of Energy Spectrum Capital, Zwolle Pipeline, LLC, and Tristate’s management for approximately $73 million in cash consideration comprised of $65 million paid at closing plus a deferred payment of $8 million due on November 1, 2012, subject to customary post-closing adjustments (“Tristate Acquisition”). The final purchase price allocation is pending the completion of the valuation of the assets acquired, liabilities assumed and settlement of the deferred amounts due in the Tristate Acquisition.

The preliminary purchase price allocation is as follows (In thousands):


Purchase price:
Cash	$	65,000
Deferred payment		8,000

Total purchase price	$	73,000


Preliminary purchase price allocation:
Cash	$	589
Accounts receivable		2,564
Prepaid expenses and other		365
Property, plant and equipment		56,261
Intangible assets		16,000

Total assets	$	75,779


Accounts payable, accrued expenses and other		1,915
Asset retirement obligation		864

Total liabilities	$	2,779


Total	$	73,000

The following table is the presentation of income for the three months ended March 31, 2011 as if we had completed the Frontier Gas, Tristate and Las Animas Acquisitions on January 1, 2011 (In thousands, except per unit data):


	Three Months Ended March 31, 2011
	Crestwood Midstream Partners LP(1)			Proforma Adjustment(2)			Combined
Revenue	$	32,380		$	19,329		$	51,709
Operating expenses		(19,776	)		(18,259	)		(38,035	)

Operating income	$	12,604		$	1,070		$	13,674


Basic earnings per unit:
Net income per limited partner	$	0.27					$	0.13
Diluted earnings per unit:
Net income per limited partner	$	0.27					$	0.13

Weighted-average number of limited partner units:
Basic		31,188						37,485
Diluted		31,324						37,621

(1)	Includes approximately two months of operating income for the Las Animas Acquisition and no operating income for the Frontier Gas and Tristate Acquisitions.

(2)	Represents approximately one month of operating income for the Las Animas Acquisition, the first quarter of 2011 of operating income for the Frontier Gas Acquisition and the first quarter of 2011 of operating income for the Tristate Acquisition.

4. INVESTMENT IN UNCONSOLIDATED AFFILIATE

On March 26, 2012, the Company contributed approximately $131 million in cash to CMM, in exchange for a 35% interest in CMM, which is held by our wholly-owned subsidiary. We funded our contribution to CMM with additional borrowings under our Credit Facility. Our 35% interest in CMM provides us with the ability to exercise significant influence over CMM, but we lack control. Accordingly, we account for our investment in CMM under the equity method of accounting. Income or loss for the three month period ended March 31, 2012 was not material.

CMM, indirectly owned 65% by Crestwood Holdings LLC and 35% by us, completed the acquisition of Antero’s gathering system assets located in Harrison and Doddridge Counties, West Virginia on March 26, 2012 for $375 million, subject to normal purchase price adjustments, in cash plus an earn-out which would allow Antero to earn additional payments of up to $40 million based upon average annual production levels achieved during 2012 and 2013.

Concurrent with the acquisition by CMM, the Company entered into an agreement with CMM to operate the acquired assets. The terms of the operating agreement provide for the reimbursement of costs incurred by the Company on behalf of CMM or in conjunction with operating CMM’s assets. For the three months ended March 31, 2012, there were no reimbursements of costs or fees under the operating agreement.

5. NET INCOME PER LIMITED PARTNER UNIT

The following is a reconciliation of the limited partner units used in the basic and diluted earnings per unit calculations for the three months ended March 31, 2012 and 2011 (In thousands, except per unit data):


	Three Months Ended March 31,
	2012		2011
Limited partners’ interest in net income	$	6,437	$	8,488

Weighted-average limited partner units - basic(1)		42,694		31,188
Effect of unvested phantom units		183		136

Weighted-average limited partner units - diluted		42,877		31,324

Basic earnings per unit:
Net income per limited partner	$	0.15	$	0.27
Diluted earnings per unit:
Net income per limited partner	$	0.15	$	0.27

(1)	Includes 6,716,730 Class C units as of March 31, 2012.

There were no units excluded from our dilutive earnings per share as we do not have any anti-dilutive units for the three months ended March 31, 2012 and 2011, respectively.

6. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following (In thousands):


	Depreciable Life		March 31, 2012			December 31, 2011
Gathering systems		20 years	$	298,434		$	298,207
Processing plants and compression facilities		20-25 years		437,575			429,908
Rights-of-way and easements		20 years		50,980			50,085
Buildings and other		5-40 years		6,100			5,958

Total				793,089			784,158
Accumulated depreciation				(98,677	)		(89,860	)

Total, net of accumulated depreciation				694,412			694,298
Land				4,674			4,674
Construction in progress				50,730			47,073

Property, plant and equipment, net			$	749,816		$	746,045

We recognized $8.8 and $5.9 million of depreciation expense on property, plant and equipment for the three months ended March 31, 2012 and 2011, respectively.

We have capitalized costs in construction in progress relating to the Tygart Valley Pipeline project under the Amended Memorandum Of Understanding with Mountaineer Keystone LLC for the three months ended March 31, 2012 of approximately $2.0 million. There were no costs recognized under this agreement in the three month period ended March 31, 2011. Additionally under the Amended Memorandum Of Understanding with Mountaineer Keystone LLC, costs incurred for certain development costs for the Tygart Valley Pipeline project are reimbursable up to $2.25 million in the event of termination of the project.

7. INTANGIBLE ASSETS

Intangible assets consist of the assigned fair value associated with the acquired gas gathering and processing contracts. The following table summarizes our intangible assets (In thousands):


	March 31, 2012			December 31, 2011
Intangible Assets	$	130,200		$	—
Additions		—			130,200

Total intangible assets	$	130,200		$	130,200
Accumulated amortization		(4,103	)		(2,440	)

Intangible Assets, net	$	126,097		$	127,760

The gas gathering and processing contracts have useful lives of 6 to 17 years, determined based upon the customer contract life. Amortization expense recorded for the three months ended March 31, 2012 was approximately $1.7 million. There was no amortization expense for the three month period ended March 31, 2011. The expected amortization of intangible assets is as follows (In thousands):


2012 (remaining)	$	4,989
2013		8,007
2014		9,176
2015		9,729
Thereafter		94,196

Total	$	126,097

8. ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER

Accounts payable, accrued expenses and other consist of the following (In thousands):


	March 31,		December 31,
	2012		2011
Accrued expenses	$	3,815	$	3,175
Accrued property taxes		1,336		5,204
Accrued product purchases payable		3,032		3,594
Tax payable		1,819		1,545
Interest payable		8,574		4,788
Accounts payable		1,687		5,128
Tristate Acquisition deferred payment		8,000		8,000
Other		356		360

Total accounts payable, accrued expenses and other	$	28,619	$	31,794

9. LONG-TERM DEBT

Debt consists of the following (In thousands):


	March 31,		December 31,
	2012		2011
Credit Facility	$	353,250	$	312,500
Senior Notes		200,000		200,000

		553,250		512,500
Current maturities of debt		—		—

Long-term debt	$	553,250	$	512,500

The following table summarizes our debt payments due by period (In thousands):


	Payments Due by Period
Long-Term Debt	Total		2012		2013		2014		2015		2016		Thereafter
Credit Facility, due October 2015	$	353,250	$	—	$	—	$	—	$	353,250	$	—	$	—
Senior Notes, due April 2019		200,000		—		—		—		—		—		200,000

Total long-term debt	$	553,250	$	—	$	—	$	—	$	353,250	$	—	$	200,000

Credit Facility— Our Credit Facility allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $500 million. On April 1, 2011, we entered into an agreement with certain lenders of our Credit Facility, which expanded our borrowing capacity from $400 million to $500 million. The Credit Facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by our wholly-owned subsidiaries. Borrowings under the Credit Facility bear interest at London Interbank Offered Rate (“LIBOR”) plus an applicable margin or a base rate as defined in the credit agreement. Under the terms of the Credit Facility, the applicable margin under LIBOR borrowings was 3.0% at March 31, 2012. Based on our results through March 31, 2012, our total availability under the Credit Facility was $474 million and our borrowings were $353.3 million. For the

three months ended March 31, 2012, our average and maximum outstanding borrowings were $247.8 million and $364.8 million, respectively. The weighted-average interest rate as of March 31, 2012 was 3.37%. The Credit Facility’s carrying value at March 31, 2012 approximates its fair value.

On March 20, 2012, we amended our Credit Agreement to permit the acquisition of an equity interest in CMM and to allow for additional investments in CMM of up to $160,000,000.

Our Credit Facility requires us to maintain:

•

a ratio of our consolidated trailing 12-month EBITDA (as defined in the credit agreement) to our net interest expense of not less than 2.5 to 1.0; and

•

a ratio of total indebtedness to consolidated trailing 12-month EBITDA (as defined in the credit agreement) of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to nine months following certain acquisitions.

As of March 31, 2012, we were in compliance with these financial covenants.

The Credit Facility contains restrictive covenants that prohibit the declaration or payment of distributions by us if a default then exists or would result therefrom, and otherwise limits the amount of distributions that we can make. An event of default may result in the acceleration of our repayment of outstanding borrowings under the Credit Facility, the termination of the Credit Facility and foreclosure on collateral.

Bridge Loans— In February 2011, in connection with the Frontier Gas Acquisition, we obtained commitments from multiple lenders for senior unsecured bridge loans in an aggregate amount up to $200 million. The commitment was terminated on April 1, 2011 in connection with the closing of the Senior Notes described below.

Senior Notes — On April 1, 2011, we issued $200 million of senior notes, which accrue interest at the rate of 7.75% per annum and mature in April 2019 (“Senior Notes”). Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. The accrued interest is payable in cash semi-annually in arrears on April 1 and October 1 of each year. Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the indenture governing the Senior Notes) to fixed charges of at least 1.75 to 1.0. As of March 31, 2012, we were in compliance with this covenant.

The fair value of the Senior Notes is determined using Level 2 inputs from public sources in accordance with Accounting Standards Codification Topic 820,Fair Value Measurement. We obtain the quoted market price at the measurement date to calculate the fair value. As of March 31, 2012, the Senior Notes had a fair value of approximately $205.3 million.

Guarantor Subsidiaries— Our subsidiaries are wholly-owned by CMLP and they are full and unconditional, joint and several guarantors of our debt. CMLP has no independent assets and no operations.

10. ASSET RETIREMENT OBLIGATIONS

Activity for asset retirement obligations is as follows (In thousands):


	March 31,		December 31,
	2012		2011
Asset retirement obligations	$	11,545	$	9,877
Incremental liability incurred		269		140
Changes in estimates		—		(724	)
Acquisitions		—		1,744
Accretion expense		164		508

Asset retirement obligations	$	11,978	$	11,545

As of March 31, 2012 and 2011, no assets were legally restricted for use in settling asset retirement obligations.

11. CAPITAL LEASES

We have compressor leases which are accounted for as capital leases. We recorded $0.7 million in amortization expense related to these capital leases for the three months ended March 31, 2012.

The total liability outstanding at March 31, 2012 related to these leases is $6.0 million. Future minimum lease payments related to capital leases are as follows (In thousands):


2012 (remaining)	$	2,144
2013		2,860
2014		1,162

Total payments		6,166
Imputed interest		(210	)

Present value of future payments	$	5,956

12. COMMITMENTS AND CONTINGENT LIABILITIES

In May 2011, a putative class action lawsuit, Ginardi v. Frontier Gas Services, LLC, et al No 4:11-cv-0420 BRW, was filed in the United States District Court of the Eastern District of Arkansas against Frontier Gas Services, LLC, Chesapeake Energy Corporation, BHP Billiton Petroleum (“BHP”), Kinder Morgan Treating, LP, and Crestwood Arkansas Pipeline LLC (which was served in August 2011) . The lawsuit alleges that the defendants’ operations pollute the atmosphere, groundwater, and soil with allegedly harmful gases, chemicals, and compounds and the facilities create excessive noise levels constituting trespass, nuisance and annoyance (the “Ginardi case”). In March 2011, a putative class action lawsuit, George Bartlett, et al, v. Frontier Gas Services, LLC, et al including Crestwood Arkansas Pipeline, LLC, Chesapeake Energy Corporation, and Kinder Morgan Treating LP, was filed in the United States District Court of the Eastern District of Arkansas (No 4 11-cv-0910 BSM) alleging the same causes as in the Ginardi case (the “Bartlett case”). In each of the Ginardi and the Bartlett case, the plaintiffs seek compensatory and punitive damages of loss of use and enjoyment of property, contamination of soil and ground water, air and atmosphere and seek future monitoring. We have filed answers in the Ginardi and Bartlett cases denying any liability. On April 19, 2012, the court denied the certification of the class action in the Ginardi case. The court has not certified or conducted a hearing on class action status in the Bartlett lawsuit. While we cannot reasonably quantify our ultimate liability, if any, for the payment of any damages or other remedial actions, neither the Ginardi nor the Bartlett cases have had, nor are they expected to have, a material impact on our results of operation or financial condition. We intend to vigorously defend against both claims and to mitigate any claims by pursuing any and all indemnification obligations to which we may be entitled with respect to the properties as well as any coverage from our insurance.

However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Casualties or Other Risks— We maintain coverage in various insurance programs, which provide us with property damage and other coverages which are customary for the nature and scope of our operations.

Management of our General Partner believes that we have adequate insurance coverage, although insurance will not cover every type of loss that we might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant loss for which we were not adequately insured, the loss could have a material impact on our results of operations, cash flows or financial condition. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts our revenues, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

Regulatory Compliance— In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management, compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial condition.

Environmental Compliance— Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, we are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At March 31, 2012, we had recorded no liabilities for environmental matters.

13. INCOME TAXES

No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners.

However, we are subject to Texas Margin tax and our current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize currently the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

See Note 14 to the consolidated financial statements in our 2011 Annual Report on Form 10-K for more information about our income taxes.

14. EQUITY PLAN

Awards of phantom units have been granted under our Third Amended and Restated 2007 Equity Plan (“2007 Equity Plan”). The following table summarizes information regarding 2012 phantom unit activity:


	Payable In Cash					Payable In Units
	Units			Weighted- Average Grant Date Fair Value		Units			Weighted- Average Grant Date Fair Value
Unvested - January 1, 2012		13,346		$	26.40		128,795		$	27.22
Vested - phantom units		—			—		(40,929	)	$	27.21
Vested - restricted units		—			—		(1,348	)	$	25.32
Issued - phantom units		—			—		115,161		$	30.30
Issued - restricted units		—			—		10,000		$	30.04
Canceled - phantom units		(384	)	$	24.14		(5,795	)	$	28.89

Unvested - March 31, 2012		12,962		$	26.47		205,884		$	29.03

At December 31, 2011, we had total unvested compensation cost of $2.2 million related to phantom units. We recognized compensation expense of approximately $0.5 million during the three months ended March 31, 2012. Grants of phantom and restricted units during the three months ended March 31, 2012 had an estimated grant date fair value of $3.8 million. We had unearned compensation expense of $4.6 million at March 31, 2012, which is generally expected to be recognized over the vesting period of three years except for grants to non-employee directors of our General Partner in lieu of cash compensation, which vest after one year. We had 42,277 phantom and restricted units vest during the three months ended March 31, 2012. At March 31, 2012, 524,242 units were available for issuance under the 2007 Equity Plan.

Under the 2007 Equity Plan, participants who have grants of issued restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the Equity Plan on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the quarter ended March 31, 2012, we withheld 414 common units to satisfy employee tax withholding obligations. The withholding of common units by us could be deemed a purchase of the common units.

See Note 15 to the consolidated financial statements in our 2011 Annual Report on Form 10-K, for a more complete description of our 2007 Equity Plan.

15. TRANSACTIONS WITH RELATED PARTIES

Omnibus Agreement— In October 2010, concurrent with Quicksilver Resources Inc.’s (“Quicksilver”) sale of all of its ownership interests in CMLP to Crestwood Holdings (“Crestwood Transaction”), we entered into an Omnibus Agreement with Crestwood Holdings and our General Partner that addresses the following matters:

•

restrictions on Crestwood Holdings’ ability to engage in certain midstream business activities or own certain related assets in the Hood, Somervell, Johnson, Tarrant, Hill, Parker, Bosque and Erath Counties in Texas;

•

Crestwood Holdings’ obligation to indemnify us for certain liabilities and our obligation to indemnify Crestwood Holdings for certain liabilities;

•

our obligation to reimburse Crestwood Holdings for all expenses incurred by Crestwood Holdings (or payments made on our behalf) in conjunction with Crestwood Holdings’ provision of general and administrative services to us, including salary and benefits of Crestwood Holdings personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are Crestwood Holdings’ employees;

•

our obligation to reimburse Crestwood Holdings for all insurance coverage expenses it incurs or payments it makes with respect to our assets; and

•

Any or all of the provisions of the Omnibus Agreement are terminable by Crestwood Holdings at its option if our General Partner is removed without cause and units held by our General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement terminates on the earlier of August 10, 2017 or at such times as Crestwood Holdings ceases to own or control a majority of the issued and outstanding voting securities of our General Partner.

Reimbursements to Crestwood Holdings pursuant to the Omnibus Agreement consisted of payments of $4.7 million and $3.8 million for the three months ended March 31, 2012 and 2011, respectively, related to expenses and payments incurred on our behalf under the Omnibus Agreement.

Quicksilver is entitled to appoint a director to our General Partner’s board of directors until the later of the second anniversary of the closing or such time as Quicksilver generates less than 50% of our consolidated revenue in any fiscal year. Pursuant to this provision, Quicksilver has designated a director to our General Partner’s board of directors. Because this Quicksilver executive serves on our General Partner’s board of directors, Quicksilver qualifies as a related party.

On April 18, 2012, Philip Cook resigned as Quicksilver’s representative on the General Partner’s board of directors and John E. Hinton, Vice President of Finance and Investor Relations of Quicksilver, was named to replace Mr. Cook effective April 18, 2012.

We entered into a number of other agreements with Quicksilver prior to and in conjunction with the Crestwood Transaction. A description of those agreements follows:

Gas Gathering and Processing Agreements— Quicksilver has agreed to dedicate all of the natural gas produced on properties operated by Quicksilver within the areas served by our Alliance, Cowtown, and Lake Arlington Systems through 2020. We recognized $30.6 million and $30.0 million in Revenue — related party for the three months ended March 31, 2012 and 2011, respectively.

We also entered into an agreement with Quicksilver to lease pipeline assets attached to the Alliance System. We recognized $0.1 million and $0.2 million of expense related to this agreement for the three months ended March 31, 2012 and 2011, respectively.

Hill County Dry System— We operated the Hill County Dry System pursuant to an operating agreement with Quicksilver effective as of the Crestwood Transaction and ended in October 2011. There were no reimbursements by Quicksilver for the three months ended March 31, 2012 and $0.1 million for the three months ended March 31, 2011, related to this agreement.

Joint Operating Agreement— We entered into an agreement with Quicksilver for the joint development of areas governed by certain of our existing commercial agreements. Quicksilver reimbursed us $0.2 million and $0.4 million for the three months ended March 31, 2012 and 2011, respectively, for services rendered related to this agreement.

Other Agreements — During 2010 we entered in an agreement with Quicksilver to lease office space in Glen Rose, Texas. We recognized $22,000 and $22,000 in expense for the three months ended March 31, 2012 and 2011, respectively, related to this agreement.

16. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Partnership Agreement

Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended, requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner. See Note 17 to the consolidated financial statements in our 2011 Annual Report for a more complete description of our distribution policy.

On January 13, 2012, we completed a public offering of 3,500,000 common units, representing limited partner interests in us, at a price of $30.73 per common unit ($29.50 per common unit, net of underwriting discounts), providing net proceeds of approximately $103.1 million. The net proceeds from the offering were used to reduce indebtedness under our Credit Facility. In connection with issuance of the common units, our General Partner did not make an additional capital contribution resulting in a reduction in our General Partner’s general partner interest in us to approximately 1.74%.

On April 12, 2012, our General Partner made an additional capital contribution of $3.4 million to us in exchange for the issuance of an additional 118,862 General Partner units, increasing the General Partner interest from 1.74% to 2%.

The following table presents distributions for 2012 and 2011 (In millions, except per unit data):


				Distribution Paid
				Limited Partners				General Partner
Payment Date	Attributable to the Quarter Ended	Per Unit Distribution		Common		Paid-In-Kind Value to Class C unitholders		General Partner interest and IDR		Paid-In- Kind Value to Class C unitholders		Total Cash		Total Distribution
2012
May 11, 2012	March 31, 2012	$	0.50	$	18.2	$	3.4	$	3.3	$	0.5	$	21.5	$	25.4
February 10, 2012	December 31, 2011	$	0.49	$	17.9	$	3.2	$	2.8	$	0.5	$	20.7	$	24.4

2011
November 10, 2011	September 30, 2011	$	0.48	$	15.8	$	3.1	$	2.3	$	0.4	$	18.1	$	21.6
August 12, 2011	June 30, 2011	$	0.46	$	15.2	$	2.9	$	1.6	$	0.2	$	16.8	$	19.9
May 13, 2011	March 31, 2011	$	0.44	$	13.7	$	2.7	$	1.1	$	0.2	$	14.8	$	17.7
February 11, 2011	December 31, 2010	$	0.43	$	13.4	$	—	$	0.9	$	—	$	14.3	$	14.3

Cash distributions include amounts paid to common unitholders. We have the option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-In-Kind Class C units based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. For the distribution that was paid February 10, 2012, attributable to the quarter ended December 31, 2011, we issued 120,095 additional Class C units. For the distribution that will be paid May 11, 2012, attributable to the quarter ended March 31, 2012, we will issue an additional 136,128 Class C units.

17. SUBSEQUENT EVENTS

Subsequent to March 31, 2012, our General Partner made an additional capital contribution of $3.4 million to us in exchange for the issuance of an additional 118,862 General Partner units, increasing the General Partner interest from 1.74% to 2%.

18. SEGMENT INFORMATION

Our operations include four reportable operating segments. These operating segments reflect the way we internally report the financial information used to make decisions and allocate resources in connection with our operations. We evaluate the performance of our operating segments based on EBITDA, which represents operating income plus, depreciation, amortization and accretion expense.

Our business segments reflect the primary geographic areas in which we operate and consist of Barnett, Fayetteville, Granite Wash, Marcellus and Other, all of which are located within the United States of America. Each of our business segments are engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs.

Other consists of those operating segments or reporting units that did not meet quantitative reporting thresholds. For the three months ended March 31, 2012, two customers accounted for 57% and 10.1% of total revenue in the Barnett and Fayetteville segments, respectively.

The following tables summarize the reportable segment data for the three months ended March 31, 2012 and 2011 (In thousands):


	Three Months Ended March 31, 2012
	Barnett		Fayetteville		Granite Wash		Marcellus		Other			Corporate			Total
Revenue	$	3,327	$	6,864	$	9,597	$	—	$	3,328		$	—		$	23,116
Revenue - related party		30,617		—		—		—		—			—			30,617

Total revenues	$	33,944	$	6,864	$	9,597	$	—	$	3,328		$	—		$	53,733
Operations and maintenance expense		6,131		2,313		517		—		750			—			9,711
Product purchases		—		83		8,300		—		590			—			8,973
General and administrative expense		—		—		—		—		—			6,738			6,738

EBITDA		27,813		4,468		780		—		1,988			(6,738	)		28,311
Depreciation, amortization and accretion expense		6,150		2,647		628		—		1,183			38			10,646

Operating income (loss)	$	21,663	$	1,821	$	152	$	—	$	805		$	(6,776	)	$	17,665


Goodwill	$	—	$	76,767	$	16,861	$	—	$	—		$	—		$	93,628
Total assets	$	539,073	$	307,765	$	77,960	$	131,250	$	83,009		$	17,282		$	1,156,339
Capital Expenditures	$	1,866	$	8,146	$	1,288	$	—	$	1,447		$	142		$	12,889

	Three Months Ended March 31, 2011
	Barnett		Fayetteville		Granite Wash		Marcellus		Other(1)			Corporate			Total
Revenue	$	1,911	$	—	$	—	$	—	$	481		$	—		$	2,392
Revenue - related party		29,988		—		—		—		—			—			29,988

Total revenues	$	31,899	$	—	$	—			$	481		$	—		$	32,380
Operations and maintenance expense		6,928		—		—		—		453			—			7,381
Product purchases		—		—		—		—		—			—			—
General and administrative expense		—		—		—		—		—			6,370			6,370

EBITDA		24,971		—		—		—		28			(6,370	)		18,629
Depreciation, amortization and accretion expense		5,983		—		—		—		40			2			6,025

Operating income (loss)	$	18,988	$	—	$	—	$	—	$	(12	)	$	(6,372	)	$	12,604


Total assets	$	556,434	$	—	$	—	$	—	$	5,668		$	24,955		$	587,057
Capital Expenditures	$	7,972	$	—	$	—	$	—	$	5,104		$	—		$	13,076

(1)	Includes approximately two months of operating income for Las Animas System, from February 1, 2011 to March 31, 2011, subsequent to the acquisition.

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

The following is a discussion of our historical consolidated financial condition and results of operations that is intended to help the reader understand our business, results of operations and financial condition.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations includes the following sections:

•

Overview and Performance Metrics

•

Current Quarter Highlights

•

Results of Operations

•

Liquidity and Capital Resources

•

Total Contractual Obligations

•

Critical Accounting Estimates

Overview and Performance Metrics

We are a growth-oriented publicly traded Delaware master limited partnership engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs produced from the geological formations of the Barnett Shale in north Texas, the Avalon Shale area of southeastern New Mexico, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Haynesville/Bossier Shale in western Louisiana and the Marcellus Shale in northern West Virginia. We began operations in 2004 to provide midstream services primarily to Quicksilver as well as to other natural gas producers in the Barnett Shale. For the three months ended March 31, 2012, Quicksilver accounted for 57% of our total consolidated revenue, including approximately 9% that is comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under Quicksilver’s Alliance System gathering agreement.

We conduct all of our operations in the midstream sector with eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. All of our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States.

The results of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fee-based and percent-of-proceeds contracts. Under our fixed fee contracts, we do not take title to the natural gas or associated NGLs, and therefore, we avoid direct commodity price exposure. Under our percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. For the three months ended March 31, 2012, the net revenues from percent-of-proceeds contracts accounted for approximately 2% of gross margin, which we define as total revenue less product purchases.

Although we do not have significant direct commodity price exposure, lower natural gas prices could have a potential negative impact on the pace of drilling in dry gas areas — such as areas in the Barnett Shale, gathered by the Alliance and Lake Arlington Dry Systems, the Fayetteville System and the Sabine System. We have four systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System, part of the Barnett segment, (ii) the Granite Wash System, (iii) and the two systems acquired by CMM in the Marcellus segment. For the three months ended March 31, 2012, our systems located in NGL rich basins contributed approximately 51% of our total revenue. A prolonged decrease in the commodity price environment could result in our customers reducing their production volumes which would cause a resulting decrease in our revenue.

Our management uses a variety of financial and operational measures to analyze our performance. We view these measures as important factors affecting our profitability and unitholder value and therefore we review them monthly for consistency and to identify trends in our operations. These performance measures are outlined below.

Volume— We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. We routinely monitor producer activity in the areas we serve to identify new supply opportunities. Our ability to achieve these objectives is impacted by:

•

the level of successful drilling and production activity in areas where our systems are located;

•

our ability to compete with other midstream companies for production volumes; and

•

our pursuit of new acquisition opportunities.

Operating and Maintenance Expenses— We consider operating and maintenance expenses in evaluating the performance of our operations. These expenses are comprised primarily of labor, parts and materials, insurance, taxes, repair and maintenance costs, utilities and contract services. Our ability to manage operating and maintenance expenses has a significant impact on our profitability and ability to pay distributions.

EBITDA and Adjusted EBITDA— We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. In addition, Adjusted EBITDA considers certain non-recurring expenses identified in a specific reporting period. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures of other entities. In evaluating EBITDA and Adjusted EBITDA, we believe that investors should also consider, among other things, the amount by which EBITDA or Adjusted EBITDA exceeds interest costs, how EBITDA or Adjusted EBITDA compares to principal payments on debt and how EBITDA or Adjusted EBITDA compares to capital expenditures for each period. A reconciliation of EBITDA and Adjusted EBITDA to amounts reported under GAAP is presented below.

EBITDA and Adjusted EBITDA are also used as a supplemental performance measure by our management and by readers of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

the ability of our assets to generate cash sufficient to pay interest costs, support our indebtedness and make cash distributions to our unitholders and General Partner;

•

our operating performance as compared to those of other companies in the midstream energy industry, without regard to financing methods, capital structure or historical cost basis; and

•

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

See our reconciliation of Net Income to EBITDA and Adjusted EBITDA in “Results of Operations”.

Current Quarter Highlights

The following events took place during the three months ended March 31, 2012, and have impacted or are likely to impact our financial condition and results of operations.

Operational and Industry Highlights

Shale gas production in the United States has grown rapidly in recent years as the natural gas industry has improved drilling and extraction methods while increasing exploration efforts. The United States has a wide distribution of shale formations containing vast resources of natural gas, NGLs and crude oil. Led by the rapid development of the Barnett Shale in Texas, shale gas activity has expanded into other areas such as the Marcellus, Fayetteville and Haynesville/Bossier shale plays.

Growth through Diversification —Our operating results reflect our ability to diversify our shale play portfolio and increase volumes not only through our base business located in the Barnett Shale, but also through strategic acquisitions in a number of lucrative shale plays in the United States. We gathered 611 MMcfd during the three months ended March 31, 2012 which is an increase of 40% from 438 MMcfd during the same period 2011. Additionally, our processed volumes increased from 122 MMcfd for the three months ended March 31, 2011 to 147 MMcfd for the same period in 2012, which represents an increase of 21% period-over-period. The increase in processing volumes reflects the operations in NGL rich areas, including the Cowtown System in our Barnett segment and the Granite Wash System, which was acquired as part of the Frontier Gas Acquisition on April 1, 2011.

Additionally in March 2012, we made an equity investment in a joint venture that purchased gathering assets in the Marcellus Shale. This investment continues to support our growth-oriented business model, and we believe this investment will enhance our ability to provide growth during 2012 and in the future.

Distribution Growth — Our strong operating cash flows during the three months ended March 31, 2012 as compared to the same period in 2011 have enabled us to raise our distribution to $0.50 per limited partner unit for the first quarter of 2012. This represents a 14% increase over the distribution for the first quarter of 2011.

Investment in an Unconsolidated Affiliate

Financing Activities

Equity Offering — On January 13, 2012, we completed a public offering of 3,500,000 common units, representing limited partner interests in us, at a price of $30.73 per common unit ($29.50 per common unit, net of underwriting discounts), providing net proceeds of approximately $103.1 million. The net proceeds from the offering were used to reduce indebtedness under our Credit Facility. In connection with issuance of the common units, our General Partner did not make an additional capital contribution resulting in a reduction in our General Partner’s general partner interest in us to approximately 1.74%.

Results of Operations

The following table summarizes our results of operations (In thousands):


	Three Months Ended March 31,
	2012		2011
Total revenues	$	53,733	$	32,380
Operations and maintenance		9,711		7,381
Product purchases		8,973		—
General and administrative		6,738		6,370
Depreciation, amortization and accretion		10,646		6,025

Operating income		17,665		12,604
Interest expense		7,557		3,006
Income tax provision		303		222

Net income	$	9,805	$	9,376
Add:
Interest expense		7,557		3,006
Income tax provision		303		222
Depreciation, amortization and accretion expense		10,646		6,025

EBITDA	$	28,311	$	18,629
Non-recurring expenses		51		1,965

Adjusted EBITDA	$	28,362	$	20,594

The following table summarizes our gathering and processing volumes by segment (In MMcf):


	Three Months Ended March 31,
	Gathering				Processing
	2012		2011		2012		2011
Barnett		40,654		38,883		12,057		10,960
Fayetteville		7,535		—		—		—
Granite Wash		1,352		—		1,345		—
Marcellus		—		—		—		—
Other		6,063		518		—		—

Total		55,604		39,401		13,402		10,960

The following table summarizes our revenues by category and by segment (In thousands):


	Three Months Ended March 31,
	Gathering				Processing				Product Sales				Total
	2012		2011		2012		2011		2012		2011		2012		2011
Barnett	$	26,060	$	24,746	$	7,884	$	7,153	$	—	$	—	$	33,944	$	31,899
Fayetteville		6,766		—		—		—		98		—		6,864		—
Granite Wash		138		—		83		—		9,376		—		9,597		—
Marcellus		—		—		—		—		—		—		—		—
Other		2,719		81		—		—		609		400		3,328		481

Total	$	35,683	$	24,827	$	7,967	$	7,153	$	10,083	$	400	$	53,733	$	32,380

The following table summarizes our operations and maintenance expense by segment (In thousands):


	Three Months Ended March 31,
	2012		2011
Barnett	$	6,131	$	6,928
Fayetteville		2,313		—
Granite Wash		517		—
Marcellus		—		—
Other		750		453

Total	$	9,711	$	7,381

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011

Total Revenueand Volumes — The increase in gathered volumes of 173 MMcfd, processing volumes of 25 MMcfd and the addition of product sales enabled us to increase our revenue by $21.4 million. The increase in volumes was due in part to the acquisitions made during 2011, which accounted for $19.4 million of the increase for the three months ended March 31, 2012. The remaining increase in revenues relates to an increase in Barnett of $2.0 million.

Operations and Maintenance Expense — The increase in operations and maintenance expense of $2.3 million was primarily related to our acquisitions in 2011. Barnett operations and maintenance expense decreased by $0.8 million compared to prior year as a result of reduced labor and lower facility operating costs despite slightly higher gathered and processed volumes.

Product Purchases — The increase in product purchases of $9.0 million was due primarily to the cost of natural gas purchased from producers, under percent-of-proceeds contracts, in the Granite Wash.

General and Administrative Expense — The increase in general and administrative expense of $0.4 million reflects the increased scope of our business operations compared to the same period for the previous year. Specifically, an increase in compensation and benefit costs due to an increase in personnel. General and administrative expense includes $0.4 million and $0.2 million of equity-based compensation expense for the quarters ended March 31, 2012 and 2011, respectively. Transaction costs included in general and administrative expense was approximately $0.1million and $2.0 million for the quarters ended March 31, 2012 and 2011, respectively.

EBITDA —EBITDA increased by $9.7 million primarily as a result of the increase in revenues described above. As a percentage of revenue, EBITDA decreased from 58% to 53% for the quarters ended March 31, 2011 and 2012, respectively. The increase in revenues and expenses includes product sales and product purchases primarily related to Granite Wash, which decreases EBITDA as a percent of revenue. Barnett’s EBITDA increased from 78% to 82% of revenues from the three months ended March 31, 2011 to the three months ended March 31, 2012 primarily due to higher revenues and lower operating and maintenance expenses. The EBITDA for Fayetteville and Granite Wash was 65% and 8%, respectively, of revenue for the quarter ended March 31, 2012. There was no comparable measure for the quarter ended March 31, 2011 as the acquisitions occurred subsequent to March 31, 2011. See Part I, Item 1, “Financial Statements (Unaudited)— Notes to the Condensed Consolidated Financial Statements— Note 18— Segment Information.”

Adjusted EBITDA —Adjusted EBITDA increased by $7.8 million primarily as a result of the increase in revenues described above. As a percentage of revenue, Adjusted EBITDA decreased from 64% to 53% for the quarters ended March 31, 2011 and 2012, respectively. Adjusted EBITDA includes transaction-related costs of $0.1 million and $2.0 million for the quarters ended March 31, 2012 and 2011, respectively. The increase in revenues and expenses includes product sales and product purchases, primarily related to Granite Wash, which decrease Adjusted EBITDA as a percent of revenue. However, as noted above, there was no comparable measure for Granite Wash for the quarter ended March 31, 2011 as the Frontier Gas Acquisition occurred subsequent to March 31, 2011.

Depreciation, Amortization and Accretion Expense —Depreciation, amortization and accretion expense increased by $4.6 million, which resulted from the assets acquired through our acquisitions during 2011. Depreciation, amortization and accretion expense related to acquired assets for the three months ended March 31, 2012 represented $4.5 million.

Interest Expense— Interest expense increased primarily due to the addition of the Senior Notes. Borrowings under the Senior Notes and our Credit Facility were principally used to fund capital projects and the investment in CMM.

The following table provides a summary of interest expense (In thousands):


	Three Months Ended March 31,
	2012			2011
Interest cost:
Credit Facility	$	3,203		$	3,042
Senior Notes		4,027			—
Capital lease interest		49			—
Write-off of deferred financing costs		369			—

Total cost		7,648			3,042
Less capitalized interest		(91	)		(36	)

Interest expense	$	7,557		$	3,006

Liquidity and Capital Resources

Our sources of liquidity include cash flows generated from operations, available borrowing capacity under our Credit Facility, and issuances of additional debt and equity in the capital markets. We believe that our sources of liquidity will be sufficient to fund our short-term working capital requirements, capital expenditures and quarterly cash distributions during 2012. The amount of distributions to unitholders is determined by the board of directors of our General Partner on a quarterly basis.

We regularly review opportunities for both greenfield growth projects and acquisitions that will enhance our financial performance. Since we distribute most of our available cash to our unitholders, we depend on a combination of borrowings under our Credit Facility and debt or equity offerings to finance the majority of our long-term growth capital expenditures or acquisitions.

Management continuously monitors our leverage position and our anticipated capital expenditures relative to our expected cash flows. We continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or refinance outstanding debt balances with longer-term notes.

Known Trends and Uncertainties Impacting Liquidity

Our financial condition and results of operations, including our liquidity and profitability, can be significantly affected by the following:

•

Concentration of Gathering Revenues from Quicksilver:For the three months ended March 31, 2012, Quicksilver accounted for 57% of our total consolidated revenue, including approximately 9% that is comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under Quicksilver’s Alliance System gathering agreement. While we have reduced our dependency upon Quicksilver through the acquisition of additional midstream assets including long term contracts with creditworthy producers such as BHP Billiton Petroleum (“BHP”), British Petroleum, Plc. (“BP”), Exxon Mobil Corporation (“ExxonMobil”) and Chesapeake Energy Corporation (“Chesapeake”), we remain dependent upon Quicksilver for a substantial percentage of our current business. The risk of revenue fluctuations in the near term is mitigated by the use of fixed-fee contracts for providing gathering, processing, treating and compression services; however, we are still susceptible to volume fluctuations. While our acquisitions reduce the concentration of risk associated with our dependency on one producer and one geographic area, we continue to regularly review opportunities for both greenfield growth projects and acquisitions in other producing basins and with other producers in the future.

•

Access to Capital Markets:During 2011, we raised approximately $500 million through debt and equity offerings and increases to our Credit Facility to fund acquisitions and growth capital projects. In January 2012, an additional $103.1 million was raised through the public issuance of common units. While we anticipate that our currently available borrowing capacity under our Credit Facility is sufficient to fund our planned level of growth capital spending in 2012, additional debt and equity offerings would be necessary to fund additional acquisitions or other growth capital projects.

•

Natural Gas Prices: Adding new volumes through our gathering systems is dependent on the drilling and completion activities of natural gas producers in the area of our operations. Although investment returns differ between natural gas basins, rich gas and dry gas reservoirs in certain natural gas basins and between various production companies, low natural gas prices may reduce the levels of drilling activity in areas around certain of our assets, particularly those that concentrate on gathering from dry gas reservoirs or are located in dry gas basins. We seek to mitigate this risk by diversifying into various geographical production basins with predominately rich gas natural gas reservoirs. We have observed that largely due to increased prices for crude oil and NGLs, producers are shifting their drilling and development plans to focus on increasing production from rich gas basins or shale plays which offer better drilling economics as compared to production from dry gas basins. We have six systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System, part of the Barnett segment, (ii) the Granite Wash System, (iii) and the four systems acquired by CMM in the Marcellus segment. For the three months ended March 31, 2012, these rich gas systems accounted for approximately 51% of our total revenues. We will continue to focus on expanding our business activities and opportunities in rich gas basins or rich gas shale plays due to the current trend of increased drilling and producer activities in these areas.

•

Regulatory Requirements: Our operations and the operations of our customers are subject to complex and evolving federal, state, local and other laws and regulations. For example, on April 17, 2012 EPA issued a final rule establishing new emission limitations for certain oil and gas facilities. These rules establish emission standards for gas wells that are hydraulically fractured (or re-fractured). These rules also establish emissions standards for natural gas processing equipment, including compressors, controllers, storage tanks, and gas processing plants. These or other federal or state initiatives relating to hydraulic fracturing or other environmental matters could impact the extent of our operations and/or give rise to or accelerate the need for additional capital projects. In addition, any further changes in laws or regulations, or delays in the issuance of required permits, may further impact the throughput on our systems.

•

Impact of Inflation and Interest Rates: Although inflation in the U.S. has been relatively low in recent years, the U.S. economy may experience a significant inflationary effect in the future. Although inflation would negatively impact the cost of our operations and cash flows through services provided to us, the majority of our gathering and processing agreements allow us to charge increased rates based on indices expected to track such inflationary trends. Interest rates have also stayed low in recent years, as compared with historical averages. Should interest rates rise, our financing costs would increase accordingly. In addition, as with other yield-oriented securities, our unit price would also be negatively impacted by higher interest rates. Higher interest rates would increase the costs of issuing debt or equity necessary to finance potential future acquisitions. However, our competitors would face similar circumstances and we expect our cost of capital to remain competitive.

Cash Flows

The following table provides a summary of our cash flows by category (In thousands):


	Three Months Ended March 31,
	2012			2011
Net cash provided by operating activities	$	22,153		$	17,362
Net cash used in investing activities		(144,139	)		(13,076	)
Net cash provided by financing activities		122,003			7,258

Operating Activities

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011 —The increase in cash flows from operating activities resulted from slightly higher net income coupled with a decrease in receivables from Quicksilver offset by lower accounts payable, accrued property taxes and accounts receivable.

Investing Activities

The midstream energy business is capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:

•

expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or

•

maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, and extend their useful lives.

We anticipate that we will continue to make capital expenditures to develop our gathering and processing assets in the producing basins in which we operate as well as opportunities to expand into new geographical areas through acquisitions and greenfield growth opportunities.

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011 — For the three months ended March 31, 2012, we spent $12.9 million on capital projects including $0.5 million related to maintenance capital expenditures. In addition, approximately $2.0 million of the $12.9 million spent on capital projects for the three months ended March 31, 2012 related to the Tygart Valley Pipeline project. Under the Amended Memorandum Of Understanding with Mountaineer Keystone LLC, costs incurred for certain development costs for the Tygart Valley Pipeline project are reimbursable up to $2.25 million in the event of termination of the project. For the three months ended March 31, 2011, we spent $13.1 million for gathering assets and processing facilities, of which $5.1 million related to the Las Animas Acquisition.

During the current year, we expect to spend $30 million on capital projects, of which approximately $6 million to $7 million is expected to be classified as maintenance capital expenditures.

In addition to the expansion of our assets through capital projects, we made a $131 million investment in CMM, a new joint venture, that acquired gathering assets from Antero, in exchange for an indirect 35% interest in CMM. Concurrent with the acquisition, CMM entered into a $200 million revolving credit facility to finance future capital requirements and working capital needs of the CMM.

Financing Activities

Three Months Ended March 31, 2012 Compared with Three Months Ended March 31, 2011 — The increase in cash flows provided by financing activities was due to net borrowings under our Credit Facility of $40.8 million and $103.1 million proceeds from the issuance of 3,500,000 common units in January 2012. This increase was primarily offset by $20.7 million in the quarterly distribution to unitholders, which increased from $14.3 million for the quarter ended March 31, 2011.

Amendment of Revolving Credit Facility. On March 20, 2012, we amended our Credit Agreement to permit the acquisition of an equity interest in CMM and to allow for additional investments in CMM of up to $160,000,000.

Long-Term Debt

For a complete description of Long-Term Debt, see Part I, Item 1, “Financial Statements (Unaudited)— Notes to the Condensed Consolidated Financial Statements— Note 9— Long-Term Debt”.

Total Contractual Obligations

The following table summarizes our total contractual obligations as of March 31, 2012 (In thousands):


	Payments Due by Period
Contractual Obligations	Total		2012 (remaining)		2013		2014		2015		2016		Thereafter
Long-term debt(1)		553,250		—		—		—		353,250		—		200,000
Scheduled interest obligations(2)(3)		150,166		20,553		27,405		27,405		24,428		15,500		34,875
Operating lease obligations(4)		5,319		2,488		1,180		750		561		110		230
Capital lease obligations(5)		6,166		2,144		2,860		1,162		—		—		—
Asset retirement obligations(6)		11,978		—		—		—		—		—		11,978

Total contractual obligations		726,879		25,185		31,445		29,317		378,239		15,610		247,083

(1)	As of March 31, 2012, we had $353.3 million outstanding under our Credit Facility and $200 million of Senior Notes.

(2)	We estimate interest payments to be approximately $15.5 million annually on our Senior Notes.

(3)

Based on our debt outstanding and interest rates in effect at March 31, 2012, we estimate interest payments to be approximately $11.9 million annually on our Credit Facility. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.3 million. If the committed amount under our Credit Facility would have been fully utilized at year-end 2012 at interest rates in effect at March 31, 2012, annual interest expense would increase by approximately $5.0 million. If interest rates on our March 31, 2012 variable debt balance of $353.3 million increase or decrease by one percentage point, our annual income will decrease or increase by $3.5 million related to interest expense.

(4)	We lease compressors, office buildings, automobiles and other property under operating leases.

(5)	We acquired compressor leases accounted for as capital leases through the Frontier Gas Acquisition on April 1, 2011. Amounts reflect our obligations under those capital leases.

(6)	For more information regarding our asset retirement obligations, see Part I, Item 1, “Financial Statements (Unaudited)— Notes to the Condensed Consolidated Financial Statements— Note 10— Asset Retirement Obligations”, none of which is expected to be due before 2016.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements within the meaning of Item 303(a)(4) of Regulation S-K.

Recently Issued Accounting Pronouncements

The information regarding recent accounting pronouncements is included in Part I, Item 1, “Notes to Condensed Consolidated Financial Statements— Note 2— Summary of Significant Accounting Policies” to this report.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within Item 1 of Part I of this Quarterly Report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. Our critical accounting estimates used in the preparation of the consolidated financial statements were discussed in Part II Item 7, “Management Discussion and Analysis of Financial Condition and Results of Operations” included in our 2011 Annual Report on Form 10-K. These critical estimates, for which no significant changes have occurred in the three months ended March 31, 2012, include estimates and assumptions pertaining to:

•

depreciation expense and cost capitalization;

•

asset retirement obligations;

•

impairment of long-lived assets; and

•

goodwill impairment.

These estimates and assumptions are based upon what we believe is the best information available at the time of the estimates or assumptions. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

Credit Risk

Our primary credit risk relates to our dependency on Quicksilver for a significant portion of our revenues, which causes us to be subject to the risk of nonpayment or late payment by Quicksilver. Quicksilver’s credit ratings are below investment grade, where they may remain for the foreseeable future. Accordingly, this risk could be higher than it might be with a more creditworthy customer or with a more diversified group of customers. As our largest customer, we remain dependent upon Quicksilver for a substantial percentage of our revenues and unless and until we further diversify our customer base, we expect to continue to be subject to non-diversified risk of nonpayment or late payment of our fees. However, our dependency on Quicksilver and the resulting credit risk has been reduced from prior periods through the acquisition of additional midstream assets, primarily through the Frontier Gas and Tristate Acquisitions, including long term contracts with investment grade customers such as BHP, BP, ExxonMobil, Devon and Enterprise Products and creditworthy producers such as Chesapeake. Additionally, we perform credit analyses of our customers on a regular basis pursuant to our corporate credit policy. We have not had any significant losses due to counter-party failures to perform.

Interest Rate Risk

Although our base interest rates remain low, our leverage ratios directly influence the spreads charged by lenders. The credit markets could also drive the spreads charged by lenders upward. As base rates or spreads increase, our financing costs will increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect that our competitors would face similar challenges with respect to funding acquisitions and capital projects. We are exposed to variable interest rate risk as a result of borrowings under our Credit Facility. The table of contractual obligations contained in Item 2 of this Quarterly Report contains more information regarding interest rate sensitivity.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15(d)-15(e) under the Exchange Act) as of the end of the period covered by this report. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner concluded that, as of March 31, 2012, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter ended March 31, 2012 that have materially affected, or are reasonable likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

In May 2011, a putative class action lawsuit, Ginardi v. Frontier Gas Services, LLC, et al No 4:11-cv-0420 BRW, was filed in the United States District Court of the Eastern District of Arkansas against Frontier Gas Services, LLC, Chesapeake Energy Corporation, BHP Billiton Petroleum, Kinder Morgan Treating, LP, and Crestwood Arkansas Pipeline LLC (which was served in August 2011). The lawsuit alleges that the defendants’ operations pollute the atmosphere, groundwater, and soil with allegedly harmful gases, chemicals, and compounds and the facilities create excessive noise levels constituting trespass, nuisance and annoyance (the “Ginardi case”). In March 2011, a putative class action lawsuit, George Bartlett, et al, v. Frontier Gas Services, LLC, et al including Crestwood Arkansas Pipeline, LLC, Chesapeake Energy Corporation, and Kinder Morgan Treating LP, was filed in the United States District Court of the Eastern District of Arkansas (No 4 11-cv-0910 BSM) alleging the same causes as in the Ginardi case (the “Bartlett case”). In each of the Ginardi and the Bartlett case, the plaintiffs seek compensatory and punitive damages of loss of use and enjoyment of property, contamination of soil and ground water, air and atmosphere and seek future monitoring. We have filed answers in the Ginardi and Bartlett cases denying any liability. On April 19, 2012, the court denied the certification of the class action in the Ginardi case. The court has not certified or conducted a hearing on class action status in the Bartlett lawsuit. While we cannot reasonably quantify our ultimate liability, if any, for the payment of any damages or other remedial actions, neither the Ginardi nor the Bartlett cases have had, nor are they expected to have, a material impact on our results of operation or financial condition. We intend to vigorously defend against both claims and to mitigate any claims by pursuing any and all indemnification obligations to which we may be entitled with respect to the properties as well as any coverage from our insurance.

From time-to-time, we are party to certain legal, regulatory or administrative proceedings that arise in the ordinary course and are incidental to our business. However, except as set forth above, there are currently no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should review our Annual Report on Form 10-K for the year ended December 31, 2011 which contains a detailed description of risk factors that may materially affect our business, financial condition, results of operations and cash flows. Aside from the additional risk factors set forth below, there were no material changes to the risk factors previously described in Part I, Item 1A. “Risk Factors” included in our Annual Report on our Form 10-K for the year ended December 31, 2011:

We do not control all of the actions by our joint ventures.

Our joint venture, Crestwood Marcellus Midstream LLC, has its own governing board. While we have influence over the joint venture as our approval is indirectly required for most significant decisions, we do not control all of the decisions of the board.

We may be required to make additional capital contributions to our joint venture.

Our joint venture may request that we make additional capital contributions to support its capital expenditure programs. If such capital contributions are required, we may not be able to obtain the financing necessary to satisfy our obligations. In the event that we elect not to participate in future capital contributions, our ownership interest in the joint venture will be diluted.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine and Safety Disclosures

Not Applicable.

Item 5. Other Information

None.

Item 6. Exhibits:

The exhibit index is incorporated herein by reference into this quarterly report on Form 10-Q.

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.


	CRESTWOOD MIDSTREAM PARTNERS LP

	By: CRESTWOOD GAS SERVICES GP LLC, its General Partner

Dated: May 8, 2012	By:	/S/ WILLIAM G. MANIAS
		William G. Manias
		Senior Vice President – Chief Financial Officer (Principal Financial Officer)

EXHIBIT INDEX

Exhibits designated by an asterisk (*) are filed herewith and those with (**) are furnished and not filed herewith, all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit No.		Description

2.1		Purchase Agreement, dated as of February 24, 2012, by and among Crestwood Marcellus Midstream LLC and Antero Resources Appalachian Corporation (filed as Exhibit 2.1 to the Company’s Form 8-K filed February 28, 2012, and included herein by reference)

*4.1		Supplemental Indenture No. 3 dated March 22, 2012, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, Crestwood Marcellus Pipeline LLC, the other Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee

10.1		Amended and Restated Limited Liability Company Agreement of Crestwood Marcellus Midstream, LLC dated March 26, 2012 (filed as Exhibit 10.1 to the Company’s Form 8-K filed March 27, 2012, and included herein by reference)

10.2		Amendment No. 1 to Credit Agreement, dated March 20, 2012, to the Credit Agreement, dated as of October 1, 2010, among Crestwood Midstream Partners LP (f/k/a Quicksilver Gas Services LP), BNP Paribas as administrative agent and collateral agent, Banc of America Securities LLC, BNP Paribas Securities Corp. and RBC Capital Markets Corporation, as joint lead arrangers and joint bookrunners, Bank of America, N.A. and Royal Bank of Canada, as syndication agents, and UBS Securities and The Royal Bank of Scotland PLC as co-documentation agents (filed as Exhibit 10.1 to the Company’s Form 8-K filed March 26, 2012, and included herein by reference)

10.3		Guarantee, dated as of February 24, 2012, by Crestwood Holdings LLC and Crestwood Midstream Partners LP, in favor of Antero Resources Appalachian Corporation (filed as Exhibit 10.1 to the Company’s 8-K filed February 28, 2012, and included herein by reference)

*31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Linkbase Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

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Legalese
Litigous
Readability	H.S. sophomore Good

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Non-accelerated filer

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