EX-99.1

Selected Financial Data

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

Quantitative and Qualitative Disclosures About Market Risk

Financial Statements and Supplementary Data

EX-99.1 3 d502566dex991.htm EX-99.1 EX-99.1

Exhibit 99.1

On February 23, 2012, we and Crestwood Holdings Partners, LLC and its affiliates (Crestwood Holdings) formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings 65% membership interest in CMM. Because we now own 100% of CMM and have the ability to control CMM’s operating and financial decisions and policies and because the limited liability company membership interest has been acquired from related parties, applicable accounting standards required the acquisition of the interest to be accounted for as a reorganization of entities under common control. Accordingly, we have consolidated CMM and have retrospectively adjusted certain items included in our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission on February 28, 2013, as further noted below to reflect the change in reporting entity.

Below is a list of terms that are common to our industry and used throughout this document:

“/d” means per day

“Bbl(s)” means barrel or barrels

“Btu” means British Thermal units, a measure of heating value

“hp” means horsepower

“Mcf” means thousand cubic feet

“MMBtu” means million Btu

“MMcf” means million cubic feet

“NGL(s)” means natural gas liquids

“Oil” includes crude oil and condensate

When we refer to “we,” “us,” “our,” or “CMLP” we are describing Crestwood Midstream Partners LP and its consolidated subsidiaries.

Item 6.

Selected Financial Data

The following selected historical financial data as of December 31, 2012 to 2008 and for the years ended December 31, 2012 to 2008 is derived from the audited consolidated financial statements for CMLP and its subsidiaries. The selected historical financial data is not necessarily indicative of results to be expected in future periods. On February 23, 2012, we and Crestwood Holdings formed the CMM joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result have the ability to control CMM’s operating and financial decisions and policies. This transaction was accounted for as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity. The selected financial data should be read together with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Report.


	Year Ended December 31,
	2012		2011		2010 ⁽¹⁾		2009			2008

Statement of Income Data:
Operating revenues	$	239,463	$	205,820	$	113,590	$	95,881		$	76,084
Operating income		75,860		73,871		47,872		43,408			37,151
Income before income taxes		40,095		46,254		34,322		34,890			28,725
Net income from continuing operations		38,889		45,003		34,872		34,491			28,472
Loss from discontinued operations		—		—		—		(1,992	)		(2,330	)
Net income		38,889		45,003		34,872		32,499			26,142

Performance Measures:
Diluted income per unit:
From continuing operations per limited partner unit	$	0.37	$	1.00	$	1.03	$	1.25		$	1.03
Net income from continuing operations per limited partner unit	$	0.37	$	1.00	$	1.03	$	1.18		$	0.95

Distributions declared per limited partner unit ⁽²⁾	$	2.02	$	1.87	$	1.66	$	1.52		$	1.39

Volumes gathered (MMcf)		301,061		208,146		125,317		93,955			70,617
Volumes processed (MMcf)		63,264		52,613		46,660		54,386			56,225

Non-GAAP Performance Measures:
EBITDA ⁽³⁾	$	127,768	$	107,683	$	70,231	$	64,238		$	50,293
Adjusted EBITDA ⁽⁴⁾		132,465		109,962		76,549		64,238			50,293

Balance Sheet Data:
Property, plant and equipment, net	$	939,846	$	746,045	$	531,371	$	482,497		$	441,863
Total assets		1,610,469		1,026,892		570,627		487,624			502,606
Long-term debt		685,161		512,500		283,504		125,400			174,900
Other long-term obligations ⁽⁵⁾		17,185		15,474		9,877		62,162			123,928
Partners’ capital		859,609		455,623		258,753		284,837			115,208

⁽¹⁾

In January 2010, we acquired from Quicksilver Resources Inc. (Quicksilver) certain midstream assets consisting of a gathering system and a compression facility, an amine treating facility and a dehydration facility in northern Tarrant and southern Denton Counties, Texas. We refer to these assets collectively as the “Alliance Assets” and the acquisition as the “Alliance Acquisition.” Due to Quicksilver’s control of CMLP through its ownership of the General Partner at the time of the Alliance Acquisition, the Alliance Acquisition is considered a transfer of net assets between entities under common control. As a result, CMLP

was required to revise its financial statements to include the financial results and operations of the Alliance Assets. As such, the selected financial data gives retroactive effect to the Alliance Acquisition as if CMLP owned the Alliance Assets since August 8, 2008, the date on which Quicksilver acquired the Alliance Assets.

⁽²⁾	Reported amounts include the fourth quarter distribution, which was paid in the first quarter of the subsequent year.

⁽³⁾

Defined as net income plus interest expense, income tax provision, and depreciation, amortization and accretion expense (EBITDA). Additional information regarding EBITDA, including a reconciliation of EBITDA to net income as determined in accordance with GAAP, is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

⁽⁴⁾

Defined as EBITDA adjusted for the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions identified in a specific reporting period. Additional information regarding Adjusted EBITDA, including a reconciliation of Adjusted EBITDA to net income as determined in accordance with GAAP, is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

⁽⁵⁾	Other long-term obligations include our capital leases and asset retirement obligations.

Item 7.

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

Overview

Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. Our MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make.

On February 23, 2012, we and Crestwood Holdings Partners, LLC and its affiliates’ (Crestwood Holdings) formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result have the ability to control CMM’s operating and financial decisions and policies. This transaction was accounted for as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity.

Listed below is a general outline of our MD&A:

•

Business and Performance Metrics

•

Current Year Highlights

•

Results of Operations

•

Liquidity and Capital Resources

•

Off Balance Sheet Arrangements and Contractual Obligations

•

Critical Accounting Estimates

Business and Performance Metrics

We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing natural gas producers in the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Marcellus Shale in northern West Virginia, the Avalon Shale/Bone Spring in southeastern New Mexico, and the Haynesville/Bossier Shale in western Louisiana. We provide midstream services to various producers that focus on developing unconventional resources across the United States. Our largest producer is Quicksilver Resources Inc. (Quicksilver). For the years ended December 31, 2012, 2011, and 2010, Quicksilver’s production volumes accounted for 43%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 4%, 5% and 7% of our total revenues for the years ended December 31, 2012, 2011 and 2010.

We conduct all of our operations in the midstream sector in 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. 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 fixed-fee and percent-of-proceeds contracts. Under our fixed-fee contracts, we do not take title to the natural gas or associated NGLs. For the year ended December 31, 2012, approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fixed-fee service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows. 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 year ended December 31, 2012, revenues from percent-of-proceeds contracts accounted for approximately 2% of our gross margin.

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 Systems), the Fayetteville Systems and the Sabine System (part of the Haynesville/Bossier Shale). We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. For the year ended December 31, 2012, our systems located in NGL rich gas basins contributed approximately 61% of our total revenues and 51% of total gathering volumes. A prolonged decrease in the commodity price environment could result in our customers reducing their production volumes which would result in a decrease in our revenues.

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.

Volumes — 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.

Operations and Maintenance Expenses — We consider operations and maintenance expenses in evaluating the performance of our operations. These expenses are comprised primarily of labor, parts and materials, insurance, taxes other than income taxes, repair and maintenance costs, utilities and contract services. Our ability to manage operations 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 accounting principles generally accepted in the United States of America (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 the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions 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 used by other companies.

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

Current Year Highlights

Below is a discussion of events that highlight our core business and financing activities.

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 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 attractive shale plays in the United States. We believe that or experience and market position will allow us to realize significant ongoing growth opportunities by developing new greenfield projects in NGL and oil plays in areas with limited or constrained infrastructure which offer attractive returns on investment and seeking bolt-on acquisitions that provide operating synergies and allow for the development of our business in rich gas infrastructure plays, similar to our acquisitions from Antero Resources Appalachian Corporation (Antero), Devon Energy Corporation (Devon) and E. Marcellus Asset Company, LLC (EMAC) . Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain.

Our consolidated systems gathered 897 MMcf/d for the year ended December 31, 2012 which is an increase of 57% from 2011 and 162% from 2010. Additionally, our processed volumes were 173 MMcf/d in 2012, an increase of 20% from 2011 and 35% from 2010. The increase in volumes resulted in a 16% increase in our overall revenues from 2011 and 111% from 2010.

Distribution Growth — For the year ended December 31, 2012, we either declared or paid distributions of $2.02 per limited partner unit, which represents an 8% increase over the distributions related to 2011 and a 22% increase over the distributions related to 2010.

Acquisitions

Antero Acquisition

On February 24, 2012, we announced the execution of an Asset Purchase Agreement related to the acquisition of gathering assets owned by Antero in the Marcellus Shale located in Harrison and Doddridge Counties, West Virginia (Antero Acquisition), and, at closing, the planned execution of a 20 year Gas Gathering and Compression Agreement (GGA) with Antero. On March 26, 2012, CMM completed the Antero Acquisition for approximately $380 million. The assets acquired by CMM consisted of a 33 mile low pressure gathering system at the time of acquisition. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion and Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant.

Additionally, CMM entered into a 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero, which provided for an area of dedication at the time of acquisition 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 GGA, Antero committed to delivery of minimum annual volumes to CMM for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s ability under the GGA to earn the amount associated with the volume deficiency during 2013.

Antero may earn additional payments of up to $40 million based upon average annual production levels achieved during 2012, 2013 and 2014. During 2012, Antero did not meet the annual production level to earn additional payments.

Devon Acquisition

On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon for approximately $87 million (the Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a 100 MMcf/d cryogenic processing facility and 23,100 hp of compression equipment, and are located in Johnson County, Texas near our Cowtown gathering system. Additionally, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we will gather and process Devon’s natural gas production from a 20,500 acre dedication. Natural gas production gathered and processed under the agreement was approximately 96 MMcf/d as of December 31, 2012. Due to the NGL rich gas quality of the natural gas production in this region of the Barnett Shale, Devon maintained an active drilling and development plan for the Johnson County area in 2012 and expects to continue to further develop the dedicated properties in 2013.

EMAC Acquisition

On December 28, 2012, CMM acquired all of the membership interests in E. Marcellus Asset Company, LLC (EMAC) for approximately $95 million, which was financed through CMM’s $200 million credit facility. EMAC’s assets consist of four compression and dehydration stations located on CMM’s gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement.

Financing Activities

Equity Offerings

During 2012, we completed public offerings of 8,100,000 common units, representing limited partner interests, providing net proceeds of approximately $218 million. The net proceeds from these offerings were used to fund the amounts paid for the Devon Acquisition and to reduce indebtedness under our Credit Facility. Our General Partner also made additional capital contributions during 2012 of approximately $6 million to maintain its 2% general partner interest. For additional information regarding our equity offerings, see Item 8. Financial Statements and Supplementary Data, Note 14. Partners’ Capital.

Credit Facility

On March 26, 2012, in conjunction with the acquisition of Antero’s gathering system assets, CMM entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million. The CMM credit facility is secured by substantially all of its assets.

Senior Notes

On November 14, 2012, we issued an additional $150 million aggregate principal amount of 7.75% Senior Notes in a private placement offering. These notes were issued as additional notes under the indenture dated April 1, 2011 among us, Crestwood Midstream Finance Corporation, the guarantors named therein, and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which we previously issued our $200 million aggregate principal amount of 7.75% Senior Notes in April 2011. The net proceeds from the offering were used to reduce our indebtedness under our CMLP credit facility.

Results of Operations

The following table summarizes our results of operations for each of the three years ended December 31, 2012 (In thousands):


	Year Ended December 31,
	2012		2011			2010
Total operating revenues	$	239,463	$	205,820		$	113,590
Product purchases		39,005		38,787			—
Operations and maintenance expense		43,108		36,303			25,702
General and administrative expense		29,582		24,153			17,657
Depreciation, amortization and accretion		51,908		33,812			22,359
Gain from exchange of property, plant and equipment		—		1,106			—

Operating income		75,860		73,871			47,872
Interest and debt expense		35,765		27,617			13,550
Income tax expense (benefit)		1,206		1,251			(550	)

Net income	$	38,889	$	45,003		$	34,872
Add:
Interest and debt expense		35,765		27,617			13,550
Income tax expense		1,206		1,251			(550	)
Depreciation, amortization and accretion expense		51,908		33,812			22,359

EBITDA	$	127,768	$	107,683		$	70,231
Expenses associated with significant items		4,697		3,385			6,318
Gain from exchange of property, plant and equipment		—		(1,106	)		—

Adjusted EBITDA	$	132,465	$	109,962		$	76,549

EBITDA in the table above includes operating results from our Barnett, Fayetteville, Granite Wash and Marcellus segments and other operations, general and administrative expenses, and the gain from exchange of property, plant and equipment. The following table summarizes the results of our Barnett, Fayetteville, Granite Wash and Marcellus segments and other operations (In thousands):


	Year Ended December 31, 2012
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Total
Gathering revenues	$	98,889	$	26,986	$	1,434	$	25,502	$	10,202	$	163,013
Processing revenues		34,003		—		130		—		—		34,133
Product sales		141		512		38,992		—		2,672		42,317

Total operating revenues	$	133,033	$	27,498	$	40,556	$	25,502	$	12,874	$	239,463
Product purchases		125		523		35,695		—		2,662		39,005
Operations and maintenance expense		26,881		8,537		2,250		2,491		2,949		43,108

EBITDA	$	106,027	$	18,438	$	2,611	$	23,011	$	7,263

Gathering volumes (in MMcf)		158,087		31,617		6,440		83,147		21,770		301,061
Processing volumes (in MMcf)		56,844		—		6,420		—		—		63,264


	Year Ended December 31, 2011
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Total
Gathering revenues	$	108,705	$	19,421	$	346	$	—	$	2,483	$	130,955
Processing revenues		31,379		—		133		—		—		31,512
Product sales		—		1,379		37,734		—		4,240		43,353

Total operating revenues	$	140,084	$	20,800	$	38,213	$	—	$	6,723	$	205,820
Product purchases		—		1,302		33,245		—		4,240		38,787
Operations and maintenance expense		25,147		8,992		1,499		—		665		36,303

EBITDA	$	114,937	$	10,506	$	3,469		—	$	1,818

Gathering volumes (in MMcf)		172,838		23,421		4,555		—		7,332		208,146
Processing volumes (in MMcf)		48,112		—		4,501		—		—		52,613


	Year Ended December 31, 2010
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Total
Gathering revenues	$	83,394	$	—	$	—	$	—	$	—	$	83,394
Processing revenues		30,196		—		—		—		—		30,196

Total operating revenues	$	113,590	$	—	$	—	$	—	$	—	$	113,590
Operations and maintenance expense		25,702		—		—		—		—		25,702

EBITDA	$	87,888		—		—		—		—

Gathering volumes (in MMcf)		125,317		—		—		—		—		125,317
Processing volumes (in MMcf)		46,660		—		—		—		—		46,660

EBITDA and Adjusted EBITDA — EBITDA for the year ended December 31, 2012 was approximately $128 million, an increase of approximately $20 million from 2011 and approximately $58 million from 2010. In the same manner, Adjusted EBITDA for the year ended December 31, 2012 was approximately $132 million, an increase of approximately $23 million from 2011 and approximately $56 million from 2010. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities, which was approximately $4 million, $3 million and $6 million for the years ended December 31, 2012, 2011 and 2010. Adjusted EBITDA also considers the impact of other significant items, including but not limited to items such as operational costs, which were less than $1 million at December 31, 2012 and the gain on the exchange of property, plant and equipment, which was approximately $1 million at December 31, 2011.

Below is a discussion of the factors that impacted EBITDA by segment for the year ended December 31, 2012 compared to 2011 and the year ended December 31, 2011 compared to 2010:

Barnett:

During the year ended December 31, 2012, our Barnett segment’s EBITDA was approximately $9 million lower than in 2011, primarily due to lower gathering revenues. During 2011, gathering revenues in our Barnett segment were higher compared to 2010, which increased our segment EBITDA by approximately $27 million.

Revenues and Volumes — Revenues in our Barnett segment decreased by approximately $7 million during the year ended December 31, 2012 compared to 2011, primarily due to lower dry gas gathering volumes. The decrease in gathering volumes primarily related to reduced production from existing wells and well shut-ins at our Alliance and Lake Arlington gathering systems. These decreases in volumes were partially offset by producers connecting 64 new wells during the year ended December 31, 2012.

Also, partially offsetting the decline in gathering revenues and volumes during 2012 was an increase in gathering and processing revenues due to the Devon Acquisition, which was completed on August 24, 2012. During the year ended December 31, 2012, the acquired assets generated approximately $7 million of gathering and processing revenues for our Barnett segment.

In addition to the items discussed above, our revenues were also unfavorably impacted by a compressor building fire that occurred on September 6, 2012 at our Corvette processing plant, which reduced revenues by approximately $0.5 million. Additional impacts to the Barnett segment’s EBITDA for the year ended December 31, 2012, as a result of the compressor building fire are further discussed below.

During 2011, we experienced an increase in gathering volumes in our Barnett segment compared to 2010, primarily from the operations of our Alliance System. The increase in revenue of approximately $26 million primarily related to the Alliance System volumes that were the result of Quicksilver’s drilling program pursuant to a joint development agreement with Eni SpA, which resulted in an increase of approximately 75 MMcf/d in gathered volumes and approximately $16 million in revenues.

Operations and Maintenance Expense — Operations and maintenance expenses in our Barnett segment increased by approximately $2 million or 7% for the year ended December 31, 2012 when compared to 2011, while remaining relatively flat from 2011 compared to 2010. The increase in operations and maintenance expenses was primarily due to (i) the Devon Acquisition; (ii) approximately $0.2 million of costs related to a condensate spill at our Corvette facility; and (iii) a compressor building fire at our Corvette processing plant. As a result of the building fire at our Corvette processing plant, we impaired assets of approximately $1.6 million, incurred repair costs of approximately $2.2 million, and recorded amounts recoverable from our insurers of approximately $3.6 million, all of which resulted in a net impact to our operations and maintenance expenses of approximately $0.2 million.

Fayetteville:

We acquired certain midstream assets in the Fayetteville Shale during 2011, which contributed 64 MMcf/d of gathering volumes and approximately $21 million in revenues in our Fayetteville segment. Our Fayetteville segment EBITDA increased approximately $8 million during the year ended December 31, 2012 compared to 2011, primarily due to higher revenues and volumes.

Revenues and Volumes — During the year ended December 31, 2012, BHP Billiton Petroleum, Plc. (BHP) connected six new wells on our Twin Groves System, contributing to an increase in revenues and volumes in our Fayetteville segment. Additionally, we recognized twelve months of revenues in 2012 versus nine months during 2011 due to the acquisition of our operations in Fayetteville on April 1, 2011.

Operations and Maintenance Expense — Operations and maintenance expenses in our Fayetteville segment during the year ended December 31, 2012 were relatively flat compared to 2011.

Granite Wash:

During 2011, we acquired certain midstream assets in the Granite Wash, which contributed 13 MMcf/d and approximately $38 million in revenues primarily related to product sales under percent-of-proceeds contracts. For the year ended December 31, 2012, our Granite Wash segment’s EBITDA was approximately $0.8 million lower than in 2011 primarily due to lower product sales margin and higher operations and maintenance expenses.

Revenues/Margin and Volumes — For the year ended December 31, 2012, Granite Wash’s EBITDA decreased compared to 2011, due to lower margins earned on our percent-of-proceeds contracts, which primarily resulted from lower NGL and natural gas prices experienced during the year ended December 31, 2012 coupled with relatively consistent costs per volume. Partially offsetting this decrease in product sales margin was higher

gathering revenues due to new wells connected by Sabine Oil and Gas LLC (Sabine) during the year ended December 31, 2012. In addition, we recognized twelve months of revenues in 2012 versus nine months during 2011 due to the acquisition of operations in Granite Wash on April 1, 2011.

Operations and Maintenance Expense — For the year ended December 31, 2012 compared to 2011, operations and maintenance expenses were higher due to the increase in volumes resulting from the new wells connected by Sabine.

Marcellus:

On February 23, 2012, we and Crestwood Holdings formed the CMM joint venture. On March 26, 2012, CMM completed the Antero Acquisition, which contributed 210 MMcf/d of gathering volumes at the time of acquisition and 302 MMcf/d for the year ended December 31, 2012. Revenues from our Marcellus segment were approximately $26 million for the year ended December 31, 2012. On December 28, 2012, CMM completed the acquisition of EMAC whose assets consisted of four compression and dehydration stations located on CMM’s gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018.

Other:

Our other operations include our assets in the Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale/Bone Spring (Las Animas System). We acquired the Sabine and Las Animas Systems during 2011. These systems contributed 20 MMcf/d of gathering volumes and approximately $7 million in revenues during 2011. For the year ended December 31, 2012, our other operations’ EBITDA increased by approximately $5 million compared to 2011, primarily due to the operations of our Sabine System.

Revenues and Volumes — The Sabine System had 50 MMcf/d in gathered volumes for the year ended December 31, 2012, which resulted in approximately $10 million in revenues for the year ended December 31, 2012. In addition, we recognized twelve months of revenues from our Sabine System in 2012 versus two months in 2011 due to the acquisition of operations in the Sabine System in November 2011. EBITDA related to our Las Animas System remained relatively unchanged for the year ended December 31, 2012 compared to 2011.

Operations and Maintenance Expense — Operations and maintenance expenses increased during the year ended December 31, 2012, primarily due to our Sabine System acquired in November 2011.

Below is a discussion of items impacting EBITDA that are not allocated to our segments.

General and Administrative Expenses — During the year ended December 31, 2012, general and administrative expenses increased by approximately $5.4 million when compared 2011, primarily due to the acquisition of the Antero assets in March 2012. General and administrative expenses include costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $4.7 million of these costs during 2012 as compared to $3.4 million in 2011. The increase in general and administrative expenses of $6.5 million for the year ended December 31, 2011 compared to 2010, was primarily due to the transition of our operations from Quicksilver as a result of Crestwood Holdings’ acquisition of its membership interest in us from Quicksilver. These costs included personnel, new administrative systems and the increased scope of business operations as a result of our acquisitions during 2011.

Also impacting our general and administrative expenses for the year ended December 31, 2012 were increases in payroll and related benefit costs, which reflects the increased scope of our business operations compared to 2011.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense — We have experienced increases in our depreciation, amortization and accretion expense primarily due to assets acquired during 2012 and 2011.

Interest and Debt Expense — Interest and debt expense increased for the year ended December 31, 2012 compared to 2011, primarily due to (i) higher outstanding balances on our CMLP credit facility; (ii) the $200 million CMM credit facility entered into in March 2012; (iii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012; and (iv) our Senior Notes issued in April 2011 being outstanding for the entire year of 2012 versus nine months during 2011. For a further discussion of our credit facilities and Senior Notes, see Item 8. Financial Statements and Supplementary Data, Note 5. Financial Instruments.

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


	Year Ended December 31,
	2012			2011			2010
Credit Facility	$	17,570		$	12,971		$	11,532
Senior Notes		17,833			12,166			—
Bridge Loan		—			2,500			—
Capital lease interest		230			179			—
Subordinated note		—			—			2,018
Other debt-related costs		423			—			—

Total cost		36,056			27,816			13,550
Less capitalized interest		(291	)		(199	)		—

Total interest and debt costs	$	35,765		$	27,617		$	13,550

Liquidity and Capital Resources

Our sources of liquidity include cash flows generated from operations, available borrowing capacity under our credit facilities, 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 cash distributions for 2013. 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 acquisitions and greenfield growth projects 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 facilities 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: While we have reduced our dependency upon Quicksilver through the acquisition of additional midstream assets that have long term contracts with creditworthy producers such as BHP, Devon, Antero, British Petroleum, Plc. (BP), XTO Energy, a subsidiary of Exxon Mobil Corporation (XTO Energy) and Chesapeake Energy Corporation (Chesapeake), we remain dependent upon Quicksilver for a substantial percentage of our current business. For the years ended December 31, 2012, 2011, and 2010 Quicksilver’s production volumes accounted for 43%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni Spa, which comprised 4%, 5% and 7% of our total revenues for the years ended December 31, 2012, 2011, and 2010. 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, our revenues may be impacted by 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 acquisitions and greenfield growth projects in other producing basins and with other producers in the future.

•

Access to Capital Markets: The borrowings under our credit facilities were $334 million as of December 31, 2012 and based on our results through December 31, 2012, our remaining available capacity under the credit facilities was $226 million. While we anticipate that our current available borrowing capacity under our credit facilities is sufficient to fund our planned level of growth capital spending for 2013, additional debt and equity offerings may be necessary to fund additional acquisitions or other growth capital projects. During 2012, 2011 and 2010, we raised approximately $618 million, $500 million and $91 million through debt and equity offerings and increases to our credit facilities to fund acquisitions and growth capital projects. In January 2013, we borrowed $129 million under our CMLP credit facility to fund the acquisition of our additional membership interest in CMM.

•

Natural Gas Prices: Adding new volumes through our gathering systems is dependent on the drilling and completion activities of natural gas producers in our areas of 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. 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 superior prices for crude oil and NGLs compared to natural gas, 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 five systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. For the year ended December 31, 2012, these rich gas systems accounted for approximately 61% 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, the United States Environmental Protection Agency 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 volumes on our systems.

•

Impact of Inflation and Interest Rates: Although inflation in the United States has been relatively low in recent years, the United States 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 remained 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):


	Year Ended December 31,
	2012			2011			2010
Net cash provided by operating activities	$	102,065		$	86,331		$	48,003
Net cash used in investing activities		(616,517	)		(456,535	)		(149,345	)
Net cash provided by financing activities		513,766			370,999			100,598

Operating Activities

Year Ended December 31, 2012 Compared to Year Ended December 31, 2011 — During the year ended December 31, 2012, we generated cash flows from operations of $102 million compared to $86 million in 2011. This increase was primarily due to higher revenues as a result of our acquisitions of the Fayetteville and Sabine Systems during 2011 and the Antero and Devon Acquisitions during 2012. Those increases were partially offset by higher operations and maintenance expenses, higher general and administrative expenses due to our asset acquisitions during 2012 and 2011, higher payroll and benefits costs due an increase in employee headcount, and increased interest costs due to higher outstanding balances on our credit facilities and Senior Notes.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010 — During the year ended December 31, 2011, our operating cash flows increased approximately $38 million compared to 2010, primarily due to the acquisition of certain midstream assets in the Fayetteville Shale and Granite Wash and the acquisition of our Las Animas and Sabine Systems. In addition, we experienced improved performance in our Barnett operations during 2011. Also contributing to the increase in our operating cash flows during 2011 was an increase in accounts payable and accrued expenses related to our operations, ad valorem taxes and interest expense due to higher outstanding balances on our Credit Facility and the issuance of our Senior Notes in April 2011. Partially offsetting these items were higher receivables from our Fayetteville and Granite Wash operations.

Investing Activities

The midstream energy business is capital intensive, requiring significant investments 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, extend their useful lives or comply with regulatory requirements.

During 2013, we expect to spend between $120 million and $150 million on capital projects, of which approximately $10 million will relate to maintenance capital expenditures. We anticipate that our expansion capital expenditures in 2013 will expand our gathering systems through additional pipelines to connect to new wells, purchase additional compression equipment and generally increase the capacity of our systems in each of our operating segments, primarily in the Marcellus segment. We expect to fund our capital expenditures through additional capital market transactions, borrowings under our credit facilities and cash generated from operations.

In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for $258 million, which was funded through $129 million of borrowings under our CMLP credit facility and the issuance of $129 million of equity to Crestwood Holdings. We believe this acquisition will increase our potential for long-term organic growth opportunities in the Marcellus Shale region.

Our cash flows from investing activities were impacted by the following significant items during the three years ended December 31, 2012, 2011 and 2010.

Year Ended December 31, 2012:

•

The Antero Acquisition for approximately $380 million;

•

The Devon Acquisition for approximately $87 million;

•

The EMAC acquisition for approximately $95 million; and

•

Capital expenditures of approximately $53 million, including $4 million related to maintenance capital expenditures.

Year Ended December 31, 2011:

•

Acquisition of the Fayetteville and Granite Wash, Las Animas and Sabine Systems for approximately $414 million; and

•

Proceeds of approximately $6 million related to the exchange of property, plant and equipment.

Year Ended December 31, 2010:

•

Distribution of approximately $80 million to Quicksilver related to the purchase of the Alliance assets; and

•

Capital expenditures of approximately $69 million for gathering assets and facilities, including approximately $50 million related to the expansion of the Alliance System.

Financing Activities

Significant items impacting our financing activities during the three years ended December 31, 2012, 2011 and 2010 included the following:

•

$218 million, $53 million and $11 million of net proceeds from the issuance of common units in 2012, 2011 and 2010;

•

$153 million in net proceeds from the issuance of Class C units in 2011;

•

$6 million from the issuance of additional general partner units to maintain the General Partners’ 2% interest during 2012;

•

$151 million net proceeds from the issuance of additional Senior Notes in 2012 and $200 million net proceeds from the issuance of Senior Notes in 2011;

•

Net repayments under our CMLP credit facility of $106 million in 2012;

•

Net borrowings under our CMM credit facility of $127 million in 2012;

•

Net borrowings under our CMLP credit facility of $29 million in 2011 and $158 million in 2010; and

•

The payment of Sabine System acquisition deferred payment of $8 million in 2012.

During the year ended December 31, 2012, we paid distributions to our unitholders of approximately $104 million, which increased by $40 million when compared to 2011 and $54 million when compared to 2010.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements.

Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, capital commitments and contractual interest amounts are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2012, for each of the periods presented (In thousands):


	Due in Less than 1 Year		Due in 1 to 3 years		Due in 3 to 5 Years		Thereafter		Total
Long-term debt:
Principal	$	—	$	—	$	333,700	$	351,461	$	685,161
Interest		36,515		73,029		69,585		33,906		213,035
Operating lease obligations		936		1,126		161		15		2,238
Capital lease obligations		4,020		3,135		219		—		7,374
Asset retirement obligations		—		—		—		14,024		14,024
Other contractual liabilities and purchase obligations		11,637		—		—		—		11,637

Total contractual obligations	$	53,178	$	77,290	$	403,665	$	399,406	$	933,539

Long-term Debt (Principal and Interest). Debt obligations included in the table above represent stated maturities. Interest payments are shown through the stated maturity date of the related debt based on (i) the contractual interest rate for fixed rate debt or (ii) current market interest rates and the contractual credit spread for variable rate debt. Based on our debt outstanding and interest rates in effect at December 31, 2012, we estimate interest payments to be approximately $9 million annually on our credit facilities. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.6 million. If the committed amount under our credit facilities would have been fully utilized at December 31, 2012 at interest rates in effect at that time, annual interest expense would increase by approximately $12 million. If interest rates on our December 31, 2012 variable debt balance of $333.7 million increase or decrease by one percentage point, our annual income will decrease or increase by $3.4 million related to interest expense. For a further discussion of our debt obligations, see Item 8. Financial Statements and Supplementary Data, Note 5. Financial Instruments.

Operating Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities.

Capital Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities.

Other Contractual Liabilities and Purchase Obligations. Included in this amount are environmental obligations included in other current liabilities on our balance sheet. Other contractual purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations. Included in these amounts are commitments for purchasing equipment related to our construction projects. For a further discussion of our environmental liability and purchase obligations, see Item 8. Financial Statements and Supplementary Data, Note 10. Commitments and Contingent Liabilities.

Critical Accounting Estimates

Our significant accounting policies are described in Item 8. Financial Statements and Supplementary Data, Note 2. Basis of Presentation and Summary of Significant Accounting Policies. The preparation of financial statements in conformity with United States generally accepted accounting principles requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our General Partner.

Receivables

At December 31, 2012, we had approximately $45 million of our accounts receivable which was primarily due from 11 customers and approximately $3 million of other receivables due from our insurance companies. We record these receivables based on an assessment of our ability to collect those receivables under the terms of the respective agreements under which they are due. We have not established an allowance for uncollectible amounts related to these accounts receivable based on our historical collection experience with our counterparties and our periodic assessment of their creditworthiness. These are significant judgments of management, and actual results could differ from these estimates of collectability.

Long-Lived Assets

Our long-lived assets consist primarily of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information and other projections on the performance of the assets acquired. Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.

We also utilize assumptions related to the useful lives and related salvage value of our long-lived assets in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized determining useful lives, actual results can, and often do, differ from our estimates.

We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess

our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. Projected cash flows of the asset are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an impairment charge for the excess of carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

During 2012, we recorded $1.6 million of impairments of our long-lived assets related to a fire at our Corvette processing plant. We did not record any impairments of our long-lived assets during 2011 or 2010.

Goodwill Impairment

Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We have assigned our goodwill to three of our operating segments (Granite Wash, Fayetteville and Haynesville) which, based on management’s judgment, we also consider reporting units for goodwill assessment purposes.

We evaluate goodwill for impairment annually on December 31, and whenever events or changes indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of the three reporting units above to its carrying value (including goodwill). If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired.

We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, discount rates and projected cash flows. Projected cash flows of the reporting unit are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

We did not record any impairments of goodwill during 2012, 2011 or 2010. We believe that a 10% decrease in our estimates of the fair value of our reporting units would not have resulted in an impairment being recorded on any of our goodwill, other than potentially the $4 million of goodwill associated with our Haynesville/Bossier Shale system as of December 31, 2012.

Asset Retirement Obligations

We have legal obligations to remove equipment and restore land when certain of our right-of-way agreements terminate or when certain of our long-lived assets reach the end of their economic life. We record a liability for the estimated cost of retiring those assets at fair value in the period in which the liability is legally or contractually incurred. The fair value is primarily based on our estimates of the amount and timing of asset retirement expenditures. We record subsequent adjustments to our asset retirement obligation liabilities if our estimates of the timing or the amount of the estimated cash flows change.

We make several assumptions about the amount and timing of our asset retirement expenditures, which can include estimates of remaining lives of the wells connected to our systems, the estimated cost to remove equipment or restore land in the future, inflation factors and credit adjusted discount rates. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Item 7A.

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 our recent acquisitions of additional midstream assets, including long term contracts with investment grade customers such as BHP, BP, XTO Energy, Devon, Antero 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 failures to perform by our counterparties.

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. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Critical Accounting Estimates, for more information regarding our interest rate sensitivity.

Item 8.

Financial Statements and Supplementary Data

Index

Below is an index to the items contained in Item 8, Financial Statements and Supplementary Data.


	Page
Report of Independent Registered Public Accounting Firm		21
Supplemental Consolidated Statements of Income		22
Supplemental Consolidated Balance Sheets		23
Supplemental Consolidated Statements of Cash Flows		24
Supplemental Consolidated Statements of Changes in Partners’ Capital		25
Notes to Supplemental Consolidated Financial Statements		26
Supplemental Financial Information
Supplemental Selected Quarterly Financial Information (Unaudited)		53

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Crestwood Midstream Partners LP

We have audited the accompanying supplemental consolidated balance sheets of Crestwood Midstream Partners LP and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related supplemental consolidated statements of income, cash flows, and changes in partners’ capital for each of the three years in the period ended December 31, 2012. These supplemental financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these supplemental financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such supplemental consolidated financial statements present fairly, in all material respects, the financial position of Crestwood Midstream Partners LP and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The supplemental consolidated financial statements give retroactive effect to the acquisition of Crestwood Marcellus Midstream LLC by the Partnership on January 8, 2013, which has been accounted for at historical cost as a reorganization of entities under common control as described in Note 1 to the supplemental consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 18, 2013

CRESTWOOD MIDSTREAM PARTNERS LP

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except for per unit data)


	Year Ended December 31,
	2012⁽¹⁾			2011			2010
Operating revenues
Gathering revenue - related party	$	88,091		$	102,427		$	77,645
Gathering revenue		74,922			28,528			5,749
Processing revenue - related party		25,652			28,798			27,590
Processing revenue		8,481			2,714			2,606
Product sales		42,317			43,353			—

Total operating revenues		239,463			205,820			113,590

Operating expenses
Product purchases		23,853			38,787			—
Product purchases - related party		15,152			—			—
Operations and maintenance		43,108			36,303			25,702
General and administrative		29,582			24,153			17,657
Depreciation, amortization and accretion		51,908			33,812			22,359

Total operating expenses		163,603			133,055			65,718

Gain from exchange of property, plant and equipment		—			1,106			—

Operating income		75,860			73,871			47,872
Interest and debt expense		(35,765	)		(27,617	)		(13,550	)

Income before income taxes		40,095			46,254			34,322
Income tax expense (benefit)		1,206			1,251			(550	)

Net income	$	38,889		$	45,003		$	34,872

General partner’s interest in net income	$	22,218		$	7,735		$	2,526
Limited partners’ interest in net income	$	16,671		$	37,268		$	32,346
Basic income per unit:
Net income per limited partner unit	$	0.37		$	1.00		$	1.11
Diluted income per unit:
Net income per limited partner unit	$	0.37		$	1.00		$	1.03

⁽¹⁾	Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1.

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

SUPPLEMENTAL CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)


	December 31,
	2012⁽¹⁾		2011
ASSETS
Current assets
Cash and cash equivalents	$	111	$	797
Accounts receivable - related party		23,755		27,312
Accounts receivable		21,636		11,926
Insurance receivable		2,920		—
Prepaid expenses and other assets		1,941		1,935

Total current assets		50,363		41,970
Property, plant and equipment, net of accumulated depreciation of $130,030 in 2012 and $89,860 in 2011		939,846		746,045
Intangible assets, net of accumulated amortization of $12,814 in 2012 and $2,440 in 2011		501,380		127,760
Goodwill		95,031		93,628
Deferred financing costs, net		22,528		16,699
Other assets		1,321		790

Total assets	$	1,610,469	$	1,026,892

LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued additions to property, plant and equipment	$	9,213	$	7,500
Capital leases		3,862		2,693
Deferred revenue		2,634		—
Accounts payable - related party		3,088		1,308
Accounts payable, accrued expenses and other liabilities		29,717		31,794

Total current liabilities		48,514		43,295
Long-term debt		685,161		512,500
Long-term capital leases		3,161		3,929
Asset retirement obligations		14,024		11,545
Commitments and contingent liabilities (Note 10)
Partners’ capital
Common unitholders (41,164,737 and 32,997,696 units issued and outstanding at December 31, 2012 and 2011)		442,348		286,945
Class C unitholders (7,165,819 and 6,596,635 units issued and outstanding at December 31, 2012 and 2011)		159,908		157,386
General partner (979,614 and 763,892 units issued and outstanding at December 31, 2012 and 2011)		257,353		11,292

Total partners’ capital		859,609		455,623

Total liabilities and partners’ capital	$	1,610,469	$	1,026,892

⁽¹⁾	Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1.

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)


	Year Ended December 31,
	2012⁽¹⁾			2011			2010
Cash flows from operating activities
Net income	$	38,889		$	45,003		$	34,872
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		51,908			33,812			22,359
Deferred income taxes		—			—			(768	)
Equity-based compensation		1,877			916			5,522
Gain from exchange of property, plant and equipment		—			(1,106	)		—
Other non-cash income items		5,234			3,473			4,961
Changes in assets and liabilities:
Accounts receivable - related party		3,557			(4,309	)		(23,003	)
Accounts receivable		(7,076	)		(7,348	)		(270	)
Insurance receivable		(1,251	)		—			—
Prepaid expenses and other assets		2,113			249			(903	)
Accounts payable - related party		1,780			(2,959	)		4,630
Accounts payable, accrued expenses and other liabilities		5,034			18,600			603

Net cash provided by operating activities		102,065			86,331			48,003

Cash flows from investing activities
Acquisitions, net of cash acquired		(563,965	)		(414,073	)		—
Capital expenditures		(52,572	)		(48,405	)		(69,069	)
Proceeds from exchange of property, plant and equipment		—			5,943			—
Proceeds from sale of property, plant and equipment		20			—			—
Distributions to Quicksilver for Alliance assets		—			—			(80,276	)

Net cash used in investing activities		(616,517	)		(456,535	)		(149,345	)

Cash flows from financing activities
Proceeds from issuance of senior notes		151,500			200,000			—
Proceeds from CMLP credit facility		411,700			215,200			426,704
Repayments of CMLP credit facility		(517,500	)		(186,204	)		(268,600	)
Proceeds from CMM credit facility		143,500			—			—
Repayments of CMM credit facility		(16,500	)		—			—
Payment of Tristate Acquisition deferred payment		(7,839	)		—			—
Payments on capital leases		(2,993	)		(1,966	)		—
Deferred financing costs paid		(11,322	)		(6,982	)		(13,568	)
Proceeds from issuance of Class C units, net		—			152,671			—
Proceeds from issuance of common units, net		217,483			53,550			11,054
Contributions from partners		249,680			8,741			—
Distributions to partners		(103,537	)		(64,011	)		(49,699	)
Taxes paid for equity-based compensation vesting		(406	)		—			(5,293	)

Net cash provided by financing activities		513,766			370,999			100,598

Change in cash and cash equivalents		(686	)		795			(744	)
Cash and cash equivalents at beginning of period		797			2			746

Cash and cash equivalents at end of period	$	111		$	797		$	2

Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	27,885		$	20,281		$	8,590

⁽¹⁾	Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1.

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

SUPPLEMENTAL CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)


	Limited Partners
	Common			Subordinated Unitholders			Class C Unitholders		General Partner			Total
Partners’ capital as of December 31, 2009	$	281,239		$	3,040		$	—	$	558		$	284,837
Issuance of units, net of offering costs		11,054			—			—		—			11,054
Conversion of subordinated note payable		57,736			—			—		—			57,736
Conversion of subordinated units		(5,879	)		5,879			—		—			—
Net income		22,614			9,732			—		2,526			34,872
Equity-based compensation		5,522			—			—		—			5,522
Taxes paid for equity-based compensation vesting		(5,293	)		—			—		—			(5,293	)
Distributions to partners		(28,648	)		(18,651	)		—		(2,400	)		(49,699	)
Distribution to Quicksilver		(80,276	)		—			—		—			(80,276	)

Partners’ capital as of December 31, 2010		258,069			—			—		684			258,753
Issuance of units, net of offering costs		53,550			—			152,671		—			206,221
Contributions by partners		—			—			—		8,741			8,741
Net income		32,553			—			4,715		7,735			45,003
Equity-based compensation		916			—			—		—			916
Distributions to partners		(58,143	)		—			—		(5,868	)		(64,011	)

Partners’ capital as of December 31, 2011		286,945			—			157,386		11,292			455,623
Issuance of units, net of offering costs		217,483			—			—		—			217,483
Contributions from partners		—			—			—		249,680			249,680
Net income⁽¹⁾		14,149						2,522		22,218			38,889
Equity-based compensation		1,877			—			—		—			1,877
Taxes paid for equity-based compensation vesting		(406	)		—			—		—			(406	)
Distributions to partners⁽¹⁾		(77,700	)		—			—		(25,837	)		(103,537	)

Partners’ capital as of December 31, 2012⁽¹⁾	$	442,348		$	—		$	159,908	$	257,353		$	859,609

⁽¹⁾	Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 1.

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS

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.”

On October 1, 2010, Quicksilver Resources Inc. (Quicksilver) sold all of its ownership interests in CMLP to Crestwood Holdings (Crestwood Transaction), the terms of which included:

•

Crestwood Holdings’ purchase of a 100% interest in our General Partner;

•

Crestwood Holdings’ purchase of 5,696,752 common units and 11,513,625 subordinated units;

•

Crestwood Holdings’ purchase of a $58 million subordinated promissory note (Subordinated Note) payable by CMLP which had a carrying value of approximately $58 million at closing; and

•

$701 million in cash paid to Quicksilver and conditional consideration in the form of potential additional cash payments from Crestwood Holdings in 2012 and 2013 of up to $72 million in the aggregate, depending upon achievement of certain defined average volume targets above an agreed threshold for 2011 and 2012, respectively.

On October 4, 2010, our name changed from Quicksilver Gas Services LP to Crestwood Midstream Partners LP and our ticker symbol on the NYSE for our publicly traded common units changed from “KGS” to “CMLP.”

On October 18, 2010, subsequent to the closing of the Crestwood Transaction, the conflicts committee of our General Partner unanimously approved the conversion of our Subordinated Note payable into 2,333,712 common units in exchange for the outstanding balance of the Subordinated Note. In addition, on November 12, 2010, our subordination period ended resulting in the conversion of 11,513,625 subordinated units to common units on a one for one basis.

On February 23, 2012, we and Crestwood Holdings formed the Crestwood Marcellus Midstream LLC (CMM) joint venture. We contributed approximately $131 million for a 35% membership interest and Crestwood Holdings contributed approximately $244 million for a 65% membership interest. We utilized available capacity under our CMLP credit facility to fund our contribution to CMM. In conjunction with the formation of CMM, we and Crestwood Holdings entered into a limited liability company agreement and an operating agreement governing CMM.

On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $258 million, which was funded through $129 million of borrowings under our CMLP credit facility, the issuance of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of 133,060 general partner units to our General Partner. As a result of the acquisition of the additional membership interest, we have the ability to control CMM’s operating and financial decisions and policies. We accounted for this transaction as a reorganization of entities under common control and accordingly, we have consolidated CMM and have retrospectively adjusted our historical financial statements as of and for the year ended December 31, 2012 to reflect the change in reporting entity.

Organizational Structure

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

LOGO

Our general partner and limited partner ownership interests as of December 31, 2012 are as follows:


	Crestwood Holdings			Public			Total
General partner interest		2.0	%		—			2.0	%
Limited partner interests:
Common unitholders		39.6	%		43.9	%		83.5	%
Class C unitholders		0.2	%		14.3	%		14.5	%

Total		41.8	%		58.2	%		100.0	%

See Note 4. Net Income Per Limited Partner Unit for additional information concerning ownership interests.

Description of Business

We conduct all of our operations in the midstream sector in 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. We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment.

2.	BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. 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. In 2012, we reclassified approximately $2.7 million from goodwill to accounts receivable and other current assets to reflect the fair value of certain contracts acquired in the Frontier Gas Acquisition (as defined in Note 3. Acquisitions) that were not recorded when the purchase price allocation was finalized for the acquired assets. This reclassification had no impact on previously reported net income, earnings per unit or partners’ capital.

On January 8, 2013, we acquired Crestwood Holdings 65% membership interest in CMM and as a result, we control the operating and financial decisions of CMM. We accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions requires us to retroactively adjust our historical results. The following tables summarize the impact of our consolidation of CMM as of and for the year ended December 31, 2012. CMM was formed on February 23, 2012, therefore we did not adjust our historical results for periods prior to the inception date of CMM. Earnings related to the recast of our historical results due to the acquisition of our 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our basic or diluted earnings per limited partner unit.


	Year Ended December 31, 2012
	As Previously Reported			CMM			Combined
	(In thousands, except per unit data)
Operating revenues	$	213,961		$	25,502		$	239,463
Operating expenses		(151,238	)		(12,365	)		(163,603	)

Operating income	$	62,723		$	13,137		$	75,860

Basic earnings per limited partner unit	$	0.37					$	0.37
Diluted earnings per limited partner unit	$	0.37					$	0.37
Weighted-average number of limited partner units:
Basic		45,223						45,223
Diluted		45,420						45,420


	As of December 31, 2012
	As Previously Presented		CMM		Eliminations			Combined
ASSETS
Current assets
Cash and cash equivalents	$	21	$	90	$	—		$	111
Accounts receivable - related party		23,863		—		(108	)		23,755
Accounts receivable		15,123		6,513		—			21,636
Other current assets		4,861		—		—			4,861

Total current assets		43,868		6,603		(108	)		50,363
Investment in unconsolidated affiliate		128,646		—		(128,646	)		—
Property, plant and equipment, net		784,371		155,475		—			939,846
Intangible assets, net		163,021		338,359		—			501,380
Other long-term assets		113,501		5,379		—			118,880

Total assets	$	1,233,407	$	505,816	$	(128,754	)	$	1,610,469

LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY

Current liabilities
Accrued additions to property, plant and equipment	$	3,829	$	5,384	$	—		$	9,213
Other current liabilities		6,950		2,634		—			9,584
Accounts payable, accrued expenses and other liabilities		27,423		2,402		(108	)		29,717

Total current liabilities		38,202		10,420		(108	)		48,514
Long-term debt		558,161		127,000		—			685,161
Other long-term liabilities		16,349		836		—			17,185
Partner’s capital/members’ equity		620,695		367,560		(128,646	)		859,609

Total liabilities and partners’ capital/members’ equity	$	1,233,407	$	505,816	$	(128,754	)	$	1,610,469

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 do not have ownership in any variable interest entities.

Use of Estimates

The preparation of our financial statements requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these financial statements. Actual results can differ from those estimates.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of less than three months to be cash or cash equivalents. Our cash equivalents consist primarily of temporary investments of cash in short-term money market instruments.

Accounts Receivable

Our accounts receivable are primarily due from Quicksilver and Antero Resources Appalachian Corporation (Antero). Each of our customers is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we do not require collateral, appropriate credit ratings are required. Receivables are generally due within 30 to 60 days. We regularly review collectability and establish an allowance

as necessary using the specific identification method. At December 31, 2012 and 2011, we have recorded no allowance for uncollectible accounts receivable. During the years ended December 31, 2012, 2011 and 2010, we experienced no significant non-payment for services.

Long-Lived Assets

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvements and expense minor items. We use the straight-line method to depreciate property, plant and equipment over the estimated useful lives of the assets.

When we retire property, plant and equipment, we charge accumulated depreciation for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value. We include gains or losses on dispositions of assets in operations and maintenance expense in our consolidated statements of income.

Our intangible assets consist of acquired gas gathering, compression and processing contracts. We amortize these contracts based on the projected cash flows associated with the contracts.

We evaluate our long-lived assets for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, we evaluate the recoverability of our carrying value based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. If the undiscounted cash flows are not sufficient to recover the long-lived asset’s carrying value, or if we decide to sell a long-lived asset or group of assets, we adjust the carrying values of the asset downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on assumptions market participants would use, including market data obtained through the sales process or an analysis of expected discounted cash flows.

Goodwill

Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment, at a minimum, annually on December 31, or whenever facts and circumstances indicate that fair value of a reporting unit is less than its carrying amount.

When testing goodwill for impairment, we assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than the carrying amount as the basis to determine if a two-step quantitative impairment test is required. Under the two-step quantitative test, the first step compares the fair value of the reporting unit to its carrying value, including goodwill. If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired. If however, the fair value does not exceed the carrying amount the second step compares the implied fair value to the carrying value of the reporting unit. If the carrying amount of a reporting unit’s goodwill exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied value is recognized as an impairment loss.

Deferred Financing Costs

Costs associated with obtaining long-term debt are amortized over the term of the related debt using the effective interest method.

Asset Retirement Obligations

We record a liability for legal or contractual obligations to retire our long-lived assets associated with right-of-way contracts we hold and our facilities whether owned or leased. We record a liability in the period the obligation is incurred and estimable. Our asset retirement liabilities are initially recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense in our consolidated statements of income.

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of the range is accrued.

We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accounts payable, accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonable estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods.

We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidate balance sheet.

Revenue Recognition

We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. For fixed-fee contracts, we recognize revenues based on the volume of natural gas gathered, processed and treated or compressed. For percent-of-proceeds contracts, we recognize revenues based on the value of products sold to third parties. We recognize revenues for our services and products when all of the following criteria are met:

•

persuasive evidence of an exchange arrangement exists;

•

services have been rendered or products delivered;

•

the price for services is fixed or determinable; and

•

collectability is reasonably assured.

Income Taxes

We are a partnership for income tax purposes and are not subject to either federal income taxes or generally to state income taxes. Our partners are responsible for their share of taxable income which may differ from income for financial statement purposes due to differences in the tax basis and financial reporting basis of assets and liabilities.

revenue apportioned to Texas. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Equity Based Compensation

Equity-based awards are valued at the closing market price of our common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period. At the time of issuance of phantom units, management of our General Partner determines whether they will be settled in cash or settled in our common units.

3.	ACQUISITIONS

2012 Acquisitions

Antero Acquisition

The GGA with Antero provided for an area of dedication at the time of acquisition 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 GGA, Antero committed to deliver minimum annual throughput volumes to us for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s potential ability to recover this amount if Antero’s 2013 throughput volumes exceed the minimum annual throughput volumes included in the GGA for 2013.

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


Purchase price:
Cash	$	381,718

Total purchase price	$	381,718

Purchase price allocation:
Property, plant and equipment	$	90,562
Intangible assets		291,218

Total assets	$	381,780

Asset retirement obligation	$	62

Total liabilities	$	62

Total	$	381,718

Our intangible assets recorded as result of the Antero Acquisition relate to the GGA with Antero. These intangible assets will be amortized over the life of the contract. Transaction costs for the Antero Acquisition for the year ended December 31, 2012 were approximately $0.6 million and were included in general and administrative expenses in our consolidated statement of income. For the period from the acquisition date (March 26, 2012) through December 31, 2012, we recorded approximately $26 million of operating revenues and $12 million of operating expenses related to the operations of the assets acquired from Antero.

Devon Acquisition

On August 24, 2012, we acquired certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon Energy Corporation (Devon) for approximately $87 million (Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a cryogenic processing facility with capacity of 100 MMcf/d and 23,100 hp of compression equipment, and are located in Johnson County, Texas (West Johnson County System) near our Cowtown gathering system. Additionally, as part of the transaction, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we gather and process Devon’s natural gas production from a 20,500 acre dedication. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase price allocation is as follows (In thousands):


Purchase price:
Cash	$	87,247

Total purchase price	$	87,247

Preliminary purchase price allocation:
Property, plant and equipment	$	41,555
Intangible assets		46,959

Total assets	$	88,514

Asset retirement obligation	$	540
Property tax liability		527
Environmental liability		200

Total liabilities	$	1,267

Total	$	87,247

Our intangible assets recorded as a result of the Devon Acquisition relate to the 20 year fixed-fee gathering, processing and compression agreement with Devon. These intangible assets will be amortized over the life of the contract.

Transactions costs for the Devon Acquisition for the year ended December 31, 2012 were approximately $1 million are included in general and administrative expenses in our consolidated statement of income. For the period from the acquisition date (August 24, 2012) through December 31, 2012, we recorded approximately $7 million of operating revenues and $5 million of operating expenses related to the operations of the assets acquired from Devon. We did not incur any significant non-operating income or expenses related to the acquired assets during that period. We believe that it is impracticable to present financial information for the acquired assets prior to the acquisition date due to the lack of availability of historical financial information related to the acquired assets, and because the 20 year fixed-fee gathering, processing and compression agreement with Devon has significantly different terms than the historical intercompany relationships between the acquired assets and Devon.

EMAC Acquisition

On December 28, 2012, CMM acquired all of the membership interest of E. Marcellus Asset Company, LLC (EMAC) from Enerven Compression, LLC (Enerven) for approximately $95 million. We financed this acquisition through our CMM $200 million Credit Facility. EMAC’s assets consist of four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia. These assets will provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase price allocation is as follows (In thousands):


Purchase price:
Cash	$	95,000

Total purchase price	$	95,000

Preliminary purchase price allocation:
Property, plant and equipment	$	45,938
Intangible assets		49,817

Total assets	$	95,755

Asset retirement obligation	$	755

Total liabilities	$	755

Total	$	95,000

Our intangible assets recorded as result of the EMAC acquisition relate to the compression services agreements with Antero. These intangible assets will be amortized over the life of the contract. Transaction costs for the EMAC acquisition for the year ended December 31, 2012 were approximately $0.3 million and were included in general and administrative expenses in our consolidated statement of income. The acquisition of EMAC was not material to our results of operations for the period from the acquisition date (December 28, 2012) to December 31, 2012.

2011 Acquisitions

Las Animas Acquisition

On February 16, 2011, we acquired certain midstream assets in the Avalon Shale trend from a group of independent producers for approximately $5 million (Las Animas Acquisition). The assets acquired consisted of approximately 46 miles of natural gas gathering pipeline located in the Morrow/Atoka trend and the Avalon Shale trend in southeastern New Mexico. The pipelines are supported by long-term fixed-fee contracts which include existing Morrow/Atoka production and dedications of approximately 55,000 acres.

The Las Animas Acquisition was recorded in property, plant and equipment at fair value of approximately $5 million. During the year ended December 31, 2011, we recognized approximately $5 million of operating revenues and $0.1 million of operating income related to this acquisition.

Frontier Gas Acquisition

On April 1, 2011, we acquired certain midstream assets in the Fayetteville Shale and the Granite Wash from Frontier Gas Services, LLC for approximately $345 million (Frontier Gas Acquisition). We financed $338 million of the purchase price through a combination of equity and debt as described in Note 5. Financial Instruments and Note 14. Partners’ Capital.

The Fayetteville assets acquired consisted of approximately 130 miles of high pressure and low pressure gathering pipelines in northwestern Arkansas with capacity of approximately 510 MMcf/d, treating capacity of approximately 165 MMcf/d and approximately 35,000 hp compression (Fayetteville System). The Fayetteville System interconnects with multiple interstate pipelines which serve the Fayetteville Shale and are supported by long-term fixed-fee contracts with producers who dedicated approximately 100,000 acres in the core of the Fayetteville Shale to us. These contracts have initial terms that extend through 2020 and include an option, by either party to the contract, to extend the contract through 2025. The Granite Wash assets acquired consisted of a 28 mile pipeline system and a 36 MMcf/d cryogenic processing plant in the Texas Panhandle (Granite Wash System). The Granite Wash System is supported by more than 13,000 dedicated acres and long-term contracts with initial terms that extend through 2022.

During 2011, we finalized the Frontier Gas Acquisition purchase price allocation, which resulted in the recognition of approximately $94 million in goodwill, of which $77 million was allocated to the Fayetteville segment and $17 million was allocated to the Granite Wash segment. The final purchase price allocation is as follows (In thousands):


Purchase price:
Cash	$	344,562

Purchase price allocation:
Accounts receivable	$	335
Prepaid expenses and other		750
Property, plant and equipment		144,505
Intangible assets		114,200
Goodwill		93,628
Other assets		178

Total assets	$	353,596

Current portion of capital leases	$	2,576
Accounts payable, accrued expenses and other		64
Long-term capital leases		6,011
Asset retirement obligations		383

Total liabilities	$	9,034

Total	$	344,562

Transactions costs for the Frontier Gas Acquisition for the year ended December 31, 2011 were approximately $5 million of which approximately $2 million was recorded in general and administrative expense and $3 million was recorded in interest expense. During the year ended December 31, 2011, we recognized approximately $59 million in operating revenues and $5 million in operating income related to this acquisition.

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 $72 million in cash consideration comprised of $64 million paid at closing plus a deferred payment of approximately $8 million, which was paid during the fourth quarter of 2012 (Tristate Acquisition).

At the time of acquisition, the Tristate assets located in Haynesville/Bossier Shale consisted of approximately 60 miles of high pressure and low pressure gathering pipelines in western Louisiana with capacity of approximately 100 MMcf/d and treating capacity of approximately 80 MMcf/d (Sabine System). The Sabine System is supported by long-term, fixed-fee contracts with producers who dedicated approximately 20,000 acres to us. These contracts have various initial terms that extend through 2019 and 2021.

During 2012, we finalized our purchase price allocation for the Tristate Acquisition, which resulted in the recognition of approximately $4 million in goodwill, primarily related to anticipated operating synergies between the assets acquired and our existing assets. The final purchase price allocation is as follows (In thousands):


Purchase price:
Cash	$	64,359
Deferred payment		8,000

Total purchase price	$	72,359

Purchase price allocation:
Cash	$	589
Accounts receivable		2,564
Prepaid expenses and other		364
Property, plant and equipment		55,568
Intangible assets		12,000
Goodwill		4,053

Total assets	$	75,138

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

Total liabilities	$	2,779

Total	$	72,359

Transaction costs of $0.3 million were recognized in general and administrative expense during 2011. During the year ended December 31, 2011, we recognized approximately $1.9 million in operating revenues and $0.9 million in operating income related to this acquisition.

Unaudited Pro Forma Information

The following table is the presentation of income for the year ended December 31, 2012 as if we had completed the EMAC acquisition on February 23, 2012, the inception date of CMM, which acquired EMAC (In thousands, except per unit data):


	Year Ended December 31, 2012
	Crestwood Midstream Partners LP			Proforma Adjustment ⁽¹⁾			Combined
Operating revenues	$	239,463		$	9,950		$	249,413
Operating expenses		(163,603	)		(7,168	)		(170,771	)

Operating income	$	75,860		$	2,782		$	78,642

Basic earnings per limited partner unit⁽²⁾	$	0.37					$	0.37
Diluted earnings per limited partner unit⁽²⁾	$	0.37					$	0.37
Weighted-average number of limited partner units:⁽²⁾
Basic		45,223						45,223
Diluted		45,420						45,420

⁽¹⁾	Represents approximately ten months of operating income for the EMAC acquisition prior to the acquisition.

⁽²⁾	Earnings related to the recast of our historical results due to the acquisition of our 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our basic or diluted earnings per limited partner unit.

The following tables are the presentation of income for the years ended December 31, 2011 and 2010 as if we had completed the Las Animas, Frontier Gas and Tristate Acquisitions on January 1, 2010 (In thousands, except per unit data):


	Year Ended December 31, 2011
	Crestwood Midstream Partners LP ⁽¹⁾			Proforma Adjustment ⁽²⁾			Combined
Operating revenues	$	205,820		$	25,827		$	231,647
Operating expenses, net of gain from exchange of property, plant and equipment		(131,949	)		(22,911	)		(154,860	)

Operating income	$	73,871		$	2,916		$	76,787

Basic earnings per limited partner unit:	$	1.00					$	0.87
Diluted earnings per limited partner unit:	$	1.00					$	0.87
Weighted-average number of limited partner units:
Basic		37,206						38,835
Diluted		37,320						38,949


	Year Ended December 31, 2010
	Crestwood Midstream Partners LP			Proforma Adjustment ⁽³⁾			Combined
Operating revenues	$	113,590		$	74,217		$	187,807
Operating expenses		(65,718	)		(70,295	)		(136,013	)

Operating income	$	47,872		$	3,922		$	51,794

Basic earnings per limited partner unit:	$	1.11					$	0.80
Diluted earnings per limited partner unit:	$	1.03					$	0.75
Weighted-average number of limited partner units:
Basic		29,070						35,561
Diluted		31,316						37,807

⁽¹⁾	Includes eleven months of operating income for the Las Animas Acquisition, nine months of operating income for the Frontier Gas Acquisition and two months of operating income for the Tristate Acquisition.

⁽²⁾	Represents approximately one month of operating income for the Las Animas Acquisition, three months of operating income for the Frontier Gas Acquisition and ten months of operating income for the Tristate Acquisition, prior to the respective acquisition.

⁽³⁾	Represents operating income for the Las Animas Acquisition, the Frontier Gas Acquisition and the Tristate Acquisition for the year ended December 31, 2010.

4.	NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Earnings per Limited Partner Unit. Our net income is allocated to the General Partner and the limited partners, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the General Partner. Basic earnings per unit are computed by dividing net income attributable to limited partner unitholders by the weighted-average number of limited partner units outstanding during each period. Diluted earnings per unit are computed using the treasury stock method, which considers the impact to net income and limited partner units from the potential issuance of limited partner units.

The tables below show the (i) allocation of net income attributable to limited partners and the (ii) net income per limited partner unit based on the number of basic and diluted limited partner units outstanding for the years ended December 31, 2012, 2011 and 2010.

Allocation of Net Income to General Partner and Limited Partners


	Year Ended December 31,
	2012			2011			2010
Net income	$	38,889		$	45,003		$	34,872
GP’s incentive distributions		(14,753	)		(7,049	)		(2,016	)

Net income after incentive distributions		24,136			37,954			32,856
GP’s interest in net income after incentive distributions		7,465			686			510

LP’s interest in net income after incentive distributions	$	16,671		$	37,268		$	32,346

Net Income Per Limited Partner Unit


	Year Ended December 31,
	2012		2011		2010
Limited partners’ interest in net income	$	16,671	$	37,268	$	32,346
Weighted-average limited partner units - basic ⁽¹⁾		45,223		37,206		29,070
Effect of unvested phantom units		197		114		2,246

Weighted-average limited partner units - diluted ⁽¹⁾		45,420		37,320		31,316

Basic earnings per unit:
Net income per limited partner	$	0.37	$	1.00	$	1.11
Diluted earnings per unit:
Net income per limited partner	$	0.37	$	1.00	$	1.03

⁽¹⁾	Includes 6,869,268 and 4,828,093 Class C units for the years ended December 31, 2012 and 2011.

There were no units excluded from our dilutive earnings per share as we do not have any anti-dilutive units for the years ended December 31, 2012, 2011 and 2010.

Distributions. Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended (Partnership Agreement), requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (as defined therein) to unitholders of record on the applicable record date, as determined by our General Partner. Our minimum quarterly distribution is $0.30 per unit, to the extent we have sufficient cash flows from operations after the establishment of cash reserve and payment of fees and expenses, including payments to our General Partner. There is no guarantee that we will pay the minimum quarterly distribution in any quarter. We are prohibited from making any distributions to unitholders if such distribution would cause an event of default or an event of default exists, under our Credit Facility or other agreements governing our long-term debt.

General Partner Interest and Incentive Distribution Rights. Our General Partner is entitled to quarterly distributions equal to its General Partner interest. As of December 31, 2012, our General Partner interest is approximately 2%, represented by 979,614 General Partner units. Our General Partner has the right, but not the obligation, to contribute a proportional amount of capital to us to maintain its current General Partner interest. The General Partner’s interest in our distributions will be reduced if we issue additional units in the future and our General Partner does not contribute a proportional amount of capital to us to maintain its General Partner interest.

Our General Partner holds incentive distribution rights (IDRs) in accordance with the Partnership Agreement. These rights pay an increasing percentage, up to a maximum of 50% of the cash we distribute from operating surplus in excess of $0.45 per unit per quarter. The maximum distribution of 50% includes distributions paid to our General Partner based on its General Partner interest and assumes that our General Partner maintains its current General Partner interest. The maximum distribution of 50% does not include any distributions that our General Partner may receive on limited partner units that it owns.

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		Cash paid to common		Paid-In- Kind Value to Class C unitholders		Cash paid to General Partner and IDR		Paid-In- Kind Value to Class C unitholders		Total Cash		Total Distribution
2013
February 12, 2013	December 31, 2012	$	0.51	$	21.0	$	3.7	$	4.1	$	0.6	$	25.1	$	29.4

2012
November 9, 2012	September 30, 2012	$	0.51	$	21.0	$	3.5	$	4.1	$	0.6	$	25.1	$	29.2
August 10, 2012	June 30, 2012	$	0.50	$	20.6	$	3.4	$	3.7	$	0.5	$	24.3	$	28.2
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

Our Class C units are substantially similar in all respects to our existing common units, representing limited partner interests, except that 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. We issued 633,084 and 473,731 additional Class C units in lieu of paying in cash quarterly distributions on our Class C units for the years ended December 31, 2012 and 2011. In February 2013, we issued an additional 183,995 Class C units in quarterly distributions. Additionally, in April 2013, our outstanding Class C units will convert to common units on a one-for-one basis. Quarterly distributions on these converted units will be paid with cash.

In conjunction with the acquisition of the 65% membership interest in CMM in January 2013, we issued 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings. Our Class D units are similar in certain respects to our existing common units and Class C units, except that we have the option to pay distributions to our Class D unitholders for a period of one year with cash or by issuing additional Paid-In-Kind Class D 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. The Class D units issued in January 2013 will not participate in the dividend paid on February 12, 2013. In March 2014, our outstanding Class D units will convert to common units on a one-for-one basis.

5.	FINANCIAL INSTRUMENTS

Fair Values

We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and would be reflected at the end of the period in which the

change occurs. During the years ended December 31, 2012 and 2011, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified.

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. As of December 31, 2012 and 2011, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments.

Credit Facilities. The fair value of our credit facilities approximates their carrying amounts as of December 31, 2012 and 2011 due primarily to the variable nature of the interest rate of the instruments, which is considered a Level 2 fair value measurement.

Senior Notes. We estimated the fair value of our Senior Notes (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances. The following table reflects the carrying value and fair value of our Senior Notes (In millions):


	As of December 31,
	2012				2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes	$	351	$	365	$	200	$	197

Debt

Our long-term debt consisted of the following at December 31 (In thousands):


	2012		2011
CMM Credit Facility, due March 2017	$	127,000	$	—
CMLP Credit Facility, due November 2017		206,700		312,500
Senior Notes, due April 2019		350,000		200,000

		683,700		512,500
Plus: Unamortized premium on Senior Notes		1,461		—

Total long-term debt	$	685,161	$	512,500

Credit Facilities

CMM Credit Facility. On March 26, 2012, in conjunction with the acquisition of Antero’s gathering system assets, we entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million (CMM Credit Facility). The CMM Credit Facility is secured by substantially all its assets.

Borrowings under the CMM Credit Facility bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate as defined in the credit agreement. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR borrowings was 2.5%. The weighted-average interest rate as of December 31, 2012 was 2.8%. Our borrowings under the CMM Credit Facility were $127 million as of December 31, 2012, and based on our results through December 31, 2012, our remaining available capacity under the credit facility was $59 million. For the period from March 26, 2012 to December 31, 2012, our average and maximum outstanding borrowings were approximately $18 million and $130 million.

Our CMM Credit Facility requires us to maintain:

•

a ratio of our trailing 12-month EBITDA (as defined in the credit agreement) to our net interest expense of not less than 2.0 to 1.0; and

•

a ratio of total indebtedness to trailing 12-month EBITDA (as defined in the credit agreement) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions.

CMLP Credit Facility. Our senior secured credit facility, as amended (CMLP Credit Facility), allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $550 million. Our CMLP Credit Facility matures on November 16, 2017 and is secured by substantially all of our assets and those of certain of our subsidiaries. As of December 31, 2012, our Credit Facility is guaranteed by our 100% owned subsidiaries except for CMM and its consolidated subsidiaries.

Borrowings under the CMLP Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the credit agreement. Under the terms of the CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.5% and 3.0% at December 31, 2012 and 2011. The weighted-average interest rate as of December 31, 2012 and 2011 was 2.8% and 3.3%. Our borrowings under the CMLP Credit Facility were approximately $207 million and $312 million as of December 31, 2012 and 2011, and based on our results through December 31, 2012, our remaining available capacity under the CMLP Credit Facility was $167 million. For the year ended December 31, 2012 and 2011, our average outstanding borrowings were $305 million and $325 million. For the year ended December 31, 2012 and 2011, our maximum outstanding borrowings were $375 million and $282 million.

Our CMLP Credit Facility requires us to maintain:

•

a ratio of our consolidated trailing 12-month EBITDA (as defined in the CMLP Credit Facility) 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 CMLP Credit Facility) 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 December 31, 2012, we were in compliance with the financial covenants under our CMM and CMLP credit facilities.

Our credit facilities contain 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.

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. On November 8, 2012, we issued an additional $150 million of these notes in a private placement offering. The $150 million senior notes have the same terms as our $200 million senior notes. The net proceeds from the offering were used to reduce our indebtedness under our Credit Facility.

Our obligations under the Senior Notes are guaranteed on an unsecured basis by certain of our current and future domestic subsidiaries. Interest is payable 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 December 31, 2012, we were in compliance with this covenant.

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 conjunction with the issuance of the Senior Notes described above. We incurred approximately $3 million of commitment fees during the year ended December 31, 2011, which was included in interest expense on our consolidated statement of income.

Subordinated Note

In August 2007, we executed the Subordinated Note payable to Quicksilver in the principal amount of $50 million. The Subordinated Note was assigned to Crestwood Holdings as part of the Crestwood Transaction on October 1, 2010. Our Credit Facility required us to terminate the Subordinated Note through the issuance of additional common units during 2010. The conversion into common units was determined based upon the average closing common unit price for a 20 trading-day period that ended October 15, 2010. We issued 2,333,712 of our common units to Crestwood Holding in exchange for the outstanding balance of the Subordinated Note at the time of the conversion.

6.	PROPERTY, PLANT AND EQUIPMENT

The table below presents the details of our property, plant and equipment (In thousands):


		December 31,
	Depreciable Life	2012			2011
Gathering systems	20 years	$	450,989		$	298,207
Processing plants and compression facilities	20-25 years		490,991			429,908
Rights-of-way and easements	20 years		60,502			50,085
Buildings and other	5-40 years		7,385			5,958
Land	—		4,698			4,674
Construction in progress	—		55,311			47,073

Property, plant and equipment			1,069,876			835,905
Accumulated depreciation			(130,030	)		(89,860	)

Property, plant and equipment, net		$	939,846		$	746,045

We have capital lease assets of approximately $12 million and $9 million included in our property, plant and equipment at December 31, 2012 and 2011.

During the year ended December 31, 2012, we recorded an impairment of approximately $1.6 million of our property, plant and equipment to write certain of our assets down to their fair value of zero (which is a Level 3 fair value measurement) as a result of a compressor building fire that occurred on September 6, 2012 at our Corvette processing plant in our Barnett Segment. This impairment, in addition to approximately $1.3 million of other operations and maintenance costs incurred related to the incident, is recoverable under our insurance policies and is recorded in Prepaid Expenses and Other current assets on our balance sheet as of December 31, 2012.

During the year ended December 31, 2011, we recorded a gain of approximately $1 million on the exchange of property, plant and equipment under an agreement with a third party to exchange the delivery of certain processing plants that were under contract. We received proceeds of approximately $6 million on the exchange.

7.	INTANGIBLE ASSETS

Our intangible assets consist of acquired gas gathering, compression and processing contracts. The following table presents the changes in our intangible assets (In thousands):


	December 31,
	2012			2011
Net intangible assets at January 1	$	127,760		$	—
Additions		383,994			130,200
Amortization expense		(10,374	)		(2,440	)

Net intangible assets at December 31	$	501,380		$	127,760

Our gas gathering and processing contracts have useful lives of 5 to 20 years, as determined based upon the anticipated life of the contracts with our customers. The expected amortization of our intangible assets as of December 31, 2012 for the next five years and in total thereafter is as follows (In thousands):


2013	$	21,983
2014		23,832
2015		25,144
2016		26,414
2017		28,678
Thereafter		375,329

Total	$	501,380

8.	ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITIES

The table below presents the details of our accounts payable, accrued expenses and other liabilities (In thousands):


	December 31,
	2012		2011
Accrued expenses	$	9,608	$	3,175
Accrued property taxes		5,638		5,204
Accrued product purchases payable		2,450		3,594
Tax payable		2,159		1,545
Interest payable		7,505		4,788
Accounts payable		2,278		5,128
Tristate Acquisition deferred payment (Note 3)		—		8,000
Other		79		360

Total accounts payable, accrued expenses and other liabilities	$	29,717	$	31,794

9.	ASSET RETIREMENT OBLIGATIONS

We have legal obligations associated with right-of-way contracts we hold and at our facilities whether owned or leased. Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations.

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2012 and 2011 (In thousands):


	December 31,
	2012		2011
Net asset retirement obligation at January 1	$	11,545	$	9,877
Liabilities incurred		425		140
Acquisitions		1,358		1,744
Accretion expense		696		508
Changes in estimate		—		(724	)

Net asset retirement obligation at December 31	$	14,024	$	11,545

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2012 and 2011.

10.

COMMITMENTS AND CONTINGENT LIABILITIES

Legal Proceedings

From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. 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. As of December 31, 2012, we had less than $0.1 million accrued for our legal proceedings.

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. 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 December 31, 2012, we had accrued approximately $0.2 million for environmental matters, which is based on our undiscounted estimate of amounts we will spend on environmental compliance and remediation. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $0.2 million to $0.3 million. We had no accruals for environmental matters at December 31, 2011.

Commitments and Purchase Obligations

Capital Leases. We have a compressor, treating facility and auto leases which are accounted for as capital leases. The terms of the agreements vary from 2013 until 2016. We recorded amortization of expense of approximately $3 million and $2 million for the years ended December 31, 2012 and 2011. We had no capital leases during 2010.

Future minimum lease payments related to our capital leases at December 31, 2012 are as follows (In thousands):


2013	$	4,020
2014		2,269
2015		866
2016		219

Total payments		7,374
Imputed interest		(351	)

Present value of future payments	$	7,023

Operating Leases. We maintain operating leases in the ordinary course of our business activities. These leases include those for office buildings and other operating facilities and equipment. The terms of the agreements vary from 2013 until 2032. Future minimum annual rental commitments under our operating leases at December 31, 2012, were as follows (In thousands):


2013	$	936
2014		687
2015		439
2016		114
2017		47
Thereafter		15

Total	$	2,238

Rental expense was approximately $7 million, $8 million and $1 million for the years ended December 31, 2012, 2011 and 2010.

Purchase Commitments. At December 31, 2012, we had capital commitments of approximately $11.6 million to purchase equipment related to our capital projects. We have other planned capital projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Other. In connection with the Antero Acquisition, we agreed to pay Antero conditional consideration in the form of potential additional cash payments of up to $40 million, depending on the achievement of certain defined average annual production levels achieved during 2012, 2013 and 2014. During 2012, Antero did not meet the annual production level to earn additional payments. Based on actual volumes received in 2012 and expected volumes, we do not believe that it is probable that Antero will be able to achieve these average annual production levels in 2013 and 2014.

11.

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. Accordingly, each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

We are responsible for our portion of the Texas Margin tax that is included in Crestwood Holdings’ consolidated Texas franchise tax return. 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 the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. For the years ended December 31, 2012, 2011 and 2010, there were no temporary differences recognized in our consolidated statements of income.

Prior to the closing of the Crestwood Transaction on October 1, 2010, our activity was included in Quicksilver’s Texas Franchise tax combined report. As a result, we had a deferred tax liability which represented the change in the tax basis and financial reporting basis of our assets and liabilities. During 2010, we reversed a deferred tax liability of $0.8 million as a result of the change in organization structure with the Crestwood Transaction.

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold would be recorded as a tax benefit or expense in the

current year. We believe that there are no uncertain tax positions that would impact our operations for the years ended December 31, 2012, 2011 and 2010 and that no provision for income tax is required for these consolidated financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

12.

EQUITY PLAN

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


	Payable In Cash					Payable In Units
	Units			Weighted- Average Grant Date Fair Value		Units			Weighted- Average Grant Date Fair Value
Unvested - December 31, 2010		—		$	—		121,526		$	27.11
Vested - phantom units		—			—		—			—
Granted - phantom units		15,294			26.77		19,411			27.56
Granted - restricted units		—			—		10,000			27.70
Cancelled - phantom units		(1,948	)		29.31		(22,142	)		27.16

Unvested - December 31, 2011		13,346		$	26.40		128,795		$	27.22
Vested - phantom units		(4,267	)		26.46		(40,929	)		27.21
Vested - restricted units		—			—		(4,682	)		27.53
Granted - phantom units		—			—		126,246			29.90
Granted - restricted units		—			—		37,500			25.67
Canceled - phantom units		(767	)		25.63		(24,938	)		28.30

Unvested - December 31, 2012		8,312		$	26.45		221,992		$	28.35

As of December 31, 2012 and 2011, we had total unamortized compensation expense of approximately $3 million and $2 million related to phantom and restricted units, which we expect will be amortized over three years (the original vesting period of these instruments), except for grants to non-employee directors of our General Partner which vest over one year. We recognized compensation expense of approximately $2 million and $1 million for the years ended December 31, 2012 and 2011, included in operating expenses on our consolidated statements of income. We granted phantom and restricted units with a grant date fair value of approximately $5 million and $0.8 million for the years ended December 31, 2012 and 2011. As of December 31, 2012 and 2011, we had 505,791 units and 633,211 units available for issuance under the 2007 Equity Plan.

Under the 2007 Equity Plan, participants who have been granted 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 2007 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. For the year ended December 31, 2012, we withheld 1,405 common units to satisfy employee tax withholding obligations. The withholding of common units by us could be deemed a purchase of the common units. There were no common units withheld to satisfy employee tax withholding obligations for the years ended December 31, 2011 and 2010.

13.

TRANSACTIONS WITH RELATED PARTIES

Affiliate Revenues and Expenses

Our General Partner is owned by Crestwood Holdings. The affiliates of Crestwood Holdings and its owners are considered our related parties, including Sabine Oil and Gas LLC, and Mountaineer Keystone, LLC. In addition, under the agreements governing the Crestwood Transaction, 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. As such, Quicksilver, qualifies as a related party.

We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases and various operating agreements.

We do not have any employees. We are managed and operated by the directors and officers of our General Partner. We have an omnibus agreement with Crestwood Holdings and our General Partner under which we reimburse Crestwood Holdings for the provision of various general and administrative services for our benefit and for direct expenses incurred by Crestwood Holdings on our behalf. Crestwood Holdings bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. Prior to the closing of the Crestwood Transaction, employees of Quicksilver provided general and administrative services for our benefit. The allocations from Crestwood Holdings and Quicksilver were based on the estimated level of effort devoted to our operations.

The table below shows overall revenues, expenses and reimbursements from our affiliates for the years ended December 31, 2012, 2011 and 2010 (In millions):


	Year Ended December 31,
	2012		2011		2010
Operating revenues	$	114	$	131	$	105
Operating expenses		35		18		21
Reimbursements of operating expenses		1		2		—	⁽¹⁾

⁽¹⁾	Amount was less than $1 million.

Distributions

Prior to Quicksilver’s sale of us to Crestwood Holdings on October 1, 2010, we paid cash distributions to Quicksilver in 2010 of approximately $80 million, including the conversion of the Subordinated Note Payable to common units for approximately $50 million.

14.

PARTNERS’ CAPITAL

During 2012 and 2011, we completed public offerings of common units, representing limited partner interests. The net proceeds from these offerings were used to reduce indebtedness under our Credit Facility and to fund our acquisitions.

In April 2011, we issued Class C units, representing limited partner interests, in a private placement offering. The net proceeds from the April 2011 offering were used to finance a portion of our Frontier Gas Acquisition. The Class C units will convert into common units on a one-for-one basis on the second anniversary of the date of issuance.

The table below presents our common unit and Class C unit issuances during 2012 and 2011 (In millions, except units and per unit data):


Issuance Date	Units			Per Unit Gross Price		Per Unit Net Price ⁽¹⁾		Net Proceeds
April 1, 2011		6,243,000	⁽²⁾	$	24.50	$	—	$	153
May 4, 2011		1,800,000		$	30.65	$	29.75		53
January 13, 2012		3,500,000		$	30.73	$	29.50		103
July 25, 2012		4,600,000	⁽³⁾	$	26.00	$	24.97		115

⁽¹⁾	Price is net of underwriting discounts.

⁽²⁾	Represents Class C units.

⁽³⁾	Includes 600,000 units that were issued in August 2012.

During 2012, our General Partner made additional capital contributions of approximately $6 million in exchange for the issuance of an additional 215,722 general partner units. During 2011, our General Partner made an additional capital contribution of approximately $9 million in exchange for the issuance of an additional 293,948 general partner units.

In January 2013, we issued 6,190,469 Class D units, representing limited partner interests in us, to Crestwood Holdings in connection with our acquisition of Crestwood Holdings’ 65% membership interest in CMM. Our Class D units are similar in certain respects to our existing common units and Class C units, except that we have the option to pay distributions to our Class D unitholders with cash or by issuing additional Paid-In-Kind Class D 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. In March 2014, our outstanding Class D units will convert to common units.

15.

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 reportable segments reflect the primary geographic areas in which we operate and consist of Barnett, Fayetteville, Granite Wash and Marcellus, all of which are located within the United States. Our reportable segments are engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs. Our Other operating segment consists of those operating segments or reporting units that did not meet quantitative reporting thresholds.

As of December 31, 2012, we managed 849 miles of natural gas gathering pipelines and approximately 259,000 hp of compression equipment. For the years ended December 31, 2012, 2011 and 2010, one of our customers in the Barnett segment, which is a related party, accounted for 47%, 64% and 93% of our total revenues. In addition, in our Fayetteville and Marcellus segments, one customer in each respective segment accounted for 11% of our total revenues for the year ended December 31, 2012.

The following table is a reconciliation of Net Income to EBITDA (In thousands):


	For the Year Ended December 31,
	2012		2011		2010
Net income	$	38,889	$	45,003	$	34,872
Add:
Interest and debt expense		35,765		27,617		13,550
Income tax expense (benefit)		1,206		1,251		(550	)
Depreciation, amortization and accretion expense		51,908		33,812		22,359

EBITDA	$	127,768	$	107,683	$	70,231

The following tables reflect our segment results as of and for the years ended December 31, 2012, 2011 and 2010 (In thousands):


	Year Ended December 31, 2012
	Barnett ⁽¹⁾		Fayetteville		Granite Wash		Marcellus ⁽²⁾		Other		Corporate			Total
Operating revenues	$	20,396	$	27,498	$	39,450	$	25,502	$	12,874	$	—		$	125,720
Operating revenues - related party		112,637		—		1,106		—		—		—			113,743
Product purchases		125		523		20,543		—		2,662		—			23,853
Product purchases - related party		—		—		15,152		—		—		—			15,152
Operations and maintenance expense		26,881		8,537		2,250		2,491		2,949		—			43,108
General and administrative expense		—		—		—		—		—		29,582			29,582

EBITDA	$	106,027	$	18,438	$	2,611	$	23,011	$	7,263	$	(29,582	)	$	127,768

Goodwill	$	—	$	76,767	$	14,211	$	—	$	4,053	$	—		$	95,031
Total assets	$	618,647	$	300,593	$	80,876	$	505,816	$	81,862	$	22,675		$	1,610,469
Capital expenditures	$	13,903	$	10,954	$	4,787	$	17,079	$	4,797	$	1,052		$	52,572

⁽¹⁾	Includes four months of operating income from the Devon Acquisition, from August 24, 2012 to December 31, 2012, subsequent to acquisition.

⁽²⁾	Includes nine months of operating income from the Antero Acquisition, from March 26, 2012 to December 31, 2012, subsequent to acquisition.


	Year Ended December 31, 2011
	Barnett		Fayetteville ⁽¹⁾		Granite Wash ⁽¹⁾		Marcellus		Other ^(2) (3)		Corporate			Total
Operating revenues	$	8,859	$	20,800	$	38,213	$	—	$	6,723	$	—		$	74,595
Operating revenues - related party		131,225		—		—		—		—		—			131,225
Product purchases		—		1,302		33,245		—		4,240		—			38,787
Operations and maintenance expense		25,147		8,992		1,499		—		665		—			36,303
General and administrative expense		—		—		—		—		—		24,153			24,153
Gain from exchange of property, plant and equipment		—		—		—		—		—		1,106			1,106

EBITDA	$	114,937	$	10,506	$	3,469	$	—	$	1,818	$	(23,047	)	$	107,683

Goodwill	$	—	$	76,767	$	16,861	$	—	$	—	$	—		$	93,628
Total assets	$	545,656	$	300,338	$	77,313	$	—	$	85,307	$	18,278		$	1,026,892
Capital expenditures	$	19,999	$	17,757	$	7,960	$	—	$	2,041	$	648		$	48,405

⁽¹⁾	Includes nine months of operating income for Fayetteville and Granite Wash, from April 1, 2011 to December 31, 2011, subsequent to acquisition.

⁽²⁾	Includes approximately eleven months of operating income for Las Animas System, from February 16, 2011 to December 31, 2011, subsequent to acquisition.

⁽³⁾	Includes two months of operating income for Sabine System, from November 1, 2011 to December 31, 2011, subsequent to acquisition.


	Year Ended December 31, 2010
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Corporate			Total
Operating revenues	$	8,355	$	—	$	—	$	—	$	—	$	—		$	8,355
Operating revenues - related party		105,235		—		—		—		—		—			105,235
Operations and maintenance expense		25,702		—		—		—		—		—			25,702
General and administrative expense		—		—		—		—		—		17,657			17,657

EBITDA	$	87,888	$	—	$	—	$	—	$	—	$	(17,657	)	$	70,231

Total assets	$	557,163	$	—	$	—	$	—	$	—	$	13,464		$	570,627
Capital expenditures	$	69,069	$	—	$	—	$	—	$	—	$	—		$	69,069

16.

CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

CMLP’s (Issuer) Credit Facility and Senior Notes are fully and unconditionally guaranteed, jointly and severally, by our present and future direct and indirect 100% owned subsidiaries (the Guarantor Subsidiaries), except for CMM and its consolidated subsidiaries (the Non-Guarantor Subsidiaries). The following reflects condensed consolidating financial information of the Issuer, Guarantor Subsidiaries, Non-Guarantor Subsidiaries, eliminating entries to combine the entities and the consolidated results of CMLP as of and for the year ended December 31, 2012. We have not reflected condensed consolidating financial information as of and for the year ended December 31, 2011 or 2010 because CMM was formed during the first quarter of 2012 and, prior to CMM’s formation, all of CMLP’s 100% owned subsidiaries fully and unconditionally guaranteed CMLP’s Credit Facility and Senior Notes and CMLP had no independent assets or operations.


	For the Year Ended December 31, 2012
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	213,961		$	25,502		$	—		$	239,463
Operating expenses		607			150,631			12,365			—			163,603

Operating income (loss)		(607	)		63,330			13,137			—			75,860
Interest and debt expense		(33,388	)		(230	)		(2,147	)		—			(35,765	)

Income(loss) before income tax		(33,995	)		63,100			10,990			—			40,095
Income tax expense		—			1,206			—			—			1,206

Income before earnings from consolidated subsidiaries		(33,995	)		61,894			10,990			—			38,889
Earnings from consolidated subsidiaries		72,884			—			—			(72,884	)		—

Net income (loss)		38,889			61,894			10,990			(72,884	)		38,889
General partner’s interest in net income		22,218			—			—			—			22,218

Limited partner’s interest in net income	$	16,671		$	61,894		$	10,990			(72,884	)	$	16,671


	As of December 31, 2012
	Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	21	$	—	$	90	$	—		$	111
Accounts receivable - related party		366,405		22,587		—		(365,237	)		23,755
Accounts receivable		608		14,515		6,513		—			21,636
Insurance receivable		—		2,920		—		—			2,920
Prepaid expenses and other		584		1,357		—		—			1,941

Total current assets		367,618		41,379		6,603		(365,237	)		50,363
Investment in consolidated affiliates		1,041,935		—		—		(1,041,935	)		—
Property, plant and equipment - net		8,519		775,852		155,475					939,846
Intangible assets - net		—		163,021		338,359		—			501,380
Goodwill		—		95,031		—		—			95,031
Deferred financing costs, net		17,149		—		5,379		—			22,528
Other assets		20		1,301		—					1,321

Total assets	$	1,435,241	$	1,076,584	$	505,816	$	(1,407,172	)	$	1,610,469

LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY

Current liabilities
Accrued additions to property, plant and equipment	$	—	$	3,829	$	5,384	$	—		$	9,213
Capital leases		429		3,433		—		—			3,862
Deferred revenue		—		—		2,634		—			2,634
Accounts payable - related party		535		367,682		—		(365,129	)		3,088
Accounts payable, accrued expenses and other liabilities		15,547		11,876		2,402		(108	)		29,717

Total current liabilities		16,511		386,820		10,420		(365,237	)		48,514
Long-term debt		558,161		—		127,000		—			685,161
Long-term capital leases		960		2,201		—		—			3,161
Asset retirement obligations		—		13,188		836					14,024
Partners’/members’ equity		859,609		674,375		367,560		(1,041,935	)		859,609

Total liabilities and partners’ capital/members’ equity	$	1,435,241	$	1,076,584	$	505,816	$	(1,407,172	)	$	1,610,469


	For the Year Ended December 31, 2012
	Issuer			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(23,613	)	$	112,880		$	16,645		$	(3,847	)	$	102,065

Investing activities:
Acquisitions, net of cash acquired		(87,247	)		—			(476,718	)		—			(563,965	)
Capital expenditures		(1,052	)		(34,441	)		(17,079	)		—			(52,572	)
Acquisition of interests in CMM		(131,250	)		—			—			131,250			—
Change in advances to affiliates, net		75,825			—			—			(75,825	)		—
Capital distribution from consolidated affiliate		2,604			—			—			(2,604	)		—
Proceeds from sale of property, plant and equipment		—			20			—			—			20

Net cash provided by (used in) investing activities		(141,120	)		(34,421	)		(493,797	)		52,821			(616,517	)

Financing activities:
Proceeds from issuance of senior notes		151,500			—			—			—			151,500
Proceeds from revolving credit facility		411,700			—			143,500			—			555,200
Repayment of revolving credit facility		(517,500	)		—			(16,500	)		—			(534,000	)
Payment of Tristate Acquisition deferred payment		(7,839	)		—			—			—			(7,839	)
Payments on capital leases		(359	)		(2,634	)		—			—			(2,993	)
Deferred financing costs paid		(4,994	)					(6,328	)					(11,322	)
Proceeds from issuance of common units, net		217,483			—			—			—			217,483
Contributions received		5,930			—			375,000			(131,250	)		249,680
Distributions paid		(91,558	)					(18,430	)		6,451			(103,537	)
Change in advances from affiliates, net		—			(75,825	)		—			75,825			—
Taxes paid for equity-based compensation vesting		(406	)					—						(406	)

Net cash provided by (used in) financing activities		163,957			(78,459	)		477,242			(48,974	)		513,766

Change in cash and cash equivalents		(776	)		—			90			—			(686	)
Cash and cash equivalents at beginning of period		797			—			—			—			797

Cash and cash equivalents at end of period	$	21		$	—		$	90		$	—		$	111

Supplemental Selected Quarterly Financial Information (Unaudited)

Financial information by quarter is summarized below (In thousands).


	Quarters Ended
	March 31		June 30		September 30		December 31
2012
Operating revenues	$	53,733	$	55,229	$	63,013	$	67,488
Operating income		17,665		15,862		23,766		18,567
Net income		9,805		6,624		14,555		7,905
Basic income per unit:
Net income per limited partner unit	$	0.15	$	0.06	$	0.15	$	0.01

Diluted income per unit:
Net income per limited partner unit	$	0.15	$	0.06	$	0.15	$	0.01

2011
Operating revenues	$	32,380	$	55,535	$	58,615	$	59,290
Operating income		12,604		20,375		20,505		20,387
Net income		9,376		10,227		13,058		12,342
Basic income per unit:
Net income per limited partner unit	$	0.27	$	0.22	$	0.27	$	0.24

Diluted income per unit:
Net income per limited partner unit	$	0.27	$	0.22	$	0.27	$	0.24