10-K 1 d464543d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2012

or

 

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

For the transition period from              to             

Commission file number: 001-33631

 

 

Crestwood Midstream Partners LP

(Exact name of registrant as specified in its charter)

 

Delaware   56-2639586

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

700 Louisiana Street, Suite 2060 Houston, Texas   77002
(Address of principal executive offices)   (Zip Code)

(832) 519-2200

Internet Website: www.crestwoodlp.com

Securities registered pursuant to Section 12(b) of the Act:

 

                                        Title of Each Class                                       

 

Name of Each Exchange on which Registered

Common Units Representing Limited Partner Interests   New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

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

 

Large accelerated filer   ¨    Accelerated filer   x
Non-accelerated filer   ¨  (Do not check if smaller reporting company)    Smaller Reporting company   ¨

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

As of June 29, 2012, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was approximately $439,727,035 based on the closing sale price of $25.86 as reported on the New York Stock Exchange.

As of February 14, 2013, the registrant has 41,214,210 common units outstanding.

 

 

Documents Incorporated by Reference:

None

 

 

 


Table of Contents

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

 

2


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

TABLE OF CONTENTS

 

PART I   

Item 1.

  Business      6   

Item 1A.

  Risk Factors      19   

Item 1B.

  Unresolved Staff Comments      38   

Item 2.

  Properties      38   

Item 3.

  Legal Proceedings      38   

Item 4.

  Mine Safety Disclosures      38   
PART II   

Item 5.

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     39   

Item 6.

  Selected Financial Data      42   

Item 7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      44   

Item 7A.

  Quantitative and Qualitative Disclosures About Market Risk      60   

Item 8.

  Financial Statements and Supplementary Data      61   

Item 9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosures      93   

Item 9A.

  Controls and Procedures      93   

Item 9B.

  Other Information      93   
PART III   

Item 10.

  Directors, Executive Officers and Corporate Governance      94   

Item 11.

  Executive Compensation      100   

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     109   

Item 13.

  Certain Relationships and Related Transactions, and Director Independence      112   

Item 14.

  Principal Accounting Fees and Services      116   
PART IV   

Item 15.

  Exhibits, Financial Statement Schedules      117   
  Signatures      130   

 

3


Table of Contents

FORWARD-LOOKING INFORMATION

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “CMLP,” or the “Partnership” are intended to mean the business and operations of Crestwood Midstream Partners LP and its consolidated subsidiaries.

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

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

 

   

changes in general economic conditions;

 

   

fluctuations in oil, natural gas and NGL prices;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

changes in the availability and cost of capital;

 

   

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

 

   

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

 

   

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

 

   

the effects of future litigation;

 

   

risks related to our substantial indebtedness; and

 

   

certain factors discussed elsewhere in this report.

These factors do not necessarily include all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to, or effect on,

 

4


Table of Contents

us or our business or operations. Also note that we provide additional cautionary discussion of risks and uncertainties in Item 1A. Risk Factors, Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and elsewhere in this report. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

 

5


Table of Contents

PART I

 

Item 1. Business

General Overview

We are a growth-oriented Delaware master limited partnership organized in 2007 to own, operate, acquire and develop midstream energy assets. Our common units are publicly-traded and listed on the NYSE under the symbol “CMLP.” Crestwood Gas Services GP LLC, our general partner (General Partner) is owned by Crestwood Holdings Partners, LLC and its affiliates (Crestwood Holdings). We are managed by our General Partner and conduct substantially all of our business through CMLP. First Reserve Management, LP (First Reserve), a private equity firm with substantial investments in the energy industry, owns a significant equity interest in Crestwood Holdings.

We own and operate 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. Approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fee-based service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows.

Organizational Structure

As of December 31, 2012, our ownership is 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
  

 

 

   

 

 

   

 

 

 

Business Strategy

Our business strategy is to capitalize on our competitive strengths to increase our revenue, profitability and cash flow by:

Pursuing growth through midstream acquisitions and greenfield development projects. We are a growth-oriented master limited partnership focused on acquiring and developing natural gas gathering, processing, treating, compression, transportation, NGL and crude oil assets in and around shale plays. We believe that our 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. Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain. This strategy was illustrated by our consolidated and unconsolidated subsidiaries acquiring approximately $562 million and $423 million of midstream assets and businesses in 2012 and 2011.

Increasing utilization of existing assets and expanding our pipeline system capacities to meet our customers’ needs and to attract new customers. We believe that the location of our existing assets and relationships with active producers position us well to capture the growing need for midstream services. We aim

 

6


Table of Contents

to attract increased gathering, processing and treating volumes by marketing our midstream services, expanding our gathering systems and providing superior customer service to natural gas producers. We will compete for new customers based on available capacity in our systems, competitive fees for service and our willingness to construct or expand facilities.

Maintaining a disciplined financial policy and financing flexibility. We have significantly grown our midstream business while maintaining a disciplined financial policy. We believe in operating with a reasonable amount of leverage as we have to date, and we expect to continue this strategy by balancing the amount of leverage with our growth objectives, cash flow and equity. Our growth strategy is also based upon our ability to access various sources of capital. We have supportive relationships with a diverse group of banks, which have committed an aggregate of $550 million under our amended and restated senior secured Credit Facility, dated November 16, 2012, which matures on November 16, 2017 (Credit Facility). We believe the available borrowing capacity under our Credit Facility, combined with cash flow from operations and our proven ability to access the capital markets will enable us to achieve our growth strategy.

Business Strengths

We believe that we are well positioned to successfully execute our primary business strategies due to the following competitive strengths:

Our assets are located in attractive shale plays. Our assets are located in shale plays which are marked by favorable characteristics such as proven production, substantial gas in-place, improving development and operating costs and existing intrastate and interstate pipeline infrastructure. We believe that our established positions in these areas give us an opportunity to expand our gathering system footprint and increase our throughput volumes and plant utilization, ultimately increasing cash flows.

A history of improving well performance and lower operating and development costs associated with our areas of operation generally enable producers to achieve attractive returns on investment through various gas price environments. In addition, certain of our assets gather and process natural gas in rich gas shale plays which typically contain NGLs. The NGLs create additional value and improved drilling economics for our producers. We operate five systems located in basis that include NGL rich gas shale plays, (i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) the two systems acquired by Crestwood Marcellus Midstream LLC (CMM, our unconsolidated affiliate) in the Marcellus segment. For the year ended December 31, 2012, our consolidated systems (i.e., excluding CMM) located in NGL rich gas basins contributed approximately 56% of our total revenues and 32% of our total gathering volumes. For the year ended December 31, 2012, our consolidated and unconsolidated systems that we operate located in NGL rich gas basins (i.e., including 100% of CMM’s results), when combined, would have contributed approximately 61% of our total consolidated and unconsolidated revenues and 51% of total consolidated and unconsolidated gathering volumes. Additionally, existing intrastate and interstate pipelines interconnect with our midstream assets to provide our customers with access to growing and diverse natural gas markets, located in the northeast, midwest and southeastern United States. These factors support continued producer drilling and development activity in the basins or shale plays in which we operate.

Our customer contracts are typically long-term and fixed fee. Our primarily fixed-fee and long-term contract structure largely eliminates our exposure to direct commodity price risk and provides us with long-term cash flow stability. More than 95% of our gross margin is derived from fixed-fee service contracts. The initial terms of a substantial number of our contracts extend through 2020. In addition, current and planned production from acreage dedications from Antero Resources Appalachian Corporation (Antero), Quicksilver Resources Inc. (Quicksilver), Devon Energy Corporation (Devon), BHP Billiton Petroleum (BHP), British Petroleum, Plc. (BP), XTO Energy, a subsidiary of Exxon Mobil Corporation (XTO Energy) and Chesapeake Energy Corporation (Chesapeake) should provide future growth.

 

7


Table of Contents

We own and operate high quality, integrated assets. Substantially all of our assets have been constructed since 2006, which enables us to provide efficient and reliable service to our producers. Our relatively new asset base in relation to our competitors benefits from both low operating costs and minimal maintenance capital requirements. The integrated nature of our operations by which we provide gathering, processing, treating, compression, transportation and sales services, positions us well to serve our customers. Our system infrastructure and capacities have been designed to accommodate long-term basin development plans.

We have an experienced, knowledgeable management team with a proven record of performance. Our senior management team has substantial experience in the oil and gas industry with a proven record of enhancing value through the acquisition, integration, development and operation of midstream companies and publicly-traded entities. We believe that this team provides us with a strong foundation for developing additional natural gas gathering and processing assets and pursuing strategic acquisition opportunities.

We have assembled an experienced business development team to lead our effort to develop greenfield opportunities. Our business development team is charged with pursuing opportunities in some of the more attractive unconventional oil and rich gas plays in North America. We expect that the majority of the initial funding for these development projects will take place at a private holding company controlled by our General Partner with funds sourced from private equity and debt placements. As these projects mature and begin generating sufficient cash flows, it is contemplated that these projects will be sold or dropped down into us through arms-length transactions providing us with a steady source of incremental cash flow.

We have strong sponsor support. First Reserve owns a significant equity interest in Crestwood Holdings, and as a result, has significant control over our operations. First Reserve has shown a strong commitment to our success to date, and we believe that they will continue to support our ongoing development. For example, during the first quarter of 2012, we formed our CMM joint venture with Crestwood Holdings, which is further discussed below. The assets which we operate in the Marcellus Systems are owned by our joint venture. We believe that First Reserve is one of the most respected and seasoned private equity investors focusing on the energy sector.

Acquisitions

We completed the following acquisitions during 2012 and 2013 to date:

CMLP Acquisitions

CMM Acquisition. During the first quarter of 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. We utilized available capacity under our 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.

In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $129 million in cash, 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 our acquisition of the additional membership interest, CMM became our wholly-owned consolidated subsidiary.

Devon Acquisition. During the third quarter of 2012, we acquired certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from 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.

 

8


Table of Contents

CMM’s Marcellus Shale Acquisitions

Antero. During the first quarter of 2012, we and Crestwood Holdings, through the CMM joint venture, acquired certain of Antero’s gathering system assets located Harrison and Doddridge Counties, West Virginia. CMM’s purchase price to acquire the assets was approximately $380 million.

Antero may earn additional payments of up to $40 million based upon average annual production levels achieved during 2012, 2013 and 2014.

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.

We operate CMM and all costs associated with its operation and the Antero assets will be reimbursed to us by CMM. Concurrent with the formation of CMM, we and Crestwood Holdings, arranged for a $200 million revolving credit facility that CMM can utilize for asset acquisitions and capital expenditures relating to the installation of gathering systems and compressor stations in the area of dedication as required by the GGA.

The area of dedication is largely located within the rich gas window of the southwestern core Marcellus Shale play in northern West Virginia. The Antero assets acquired consist of a 33 mile low pressure gathering system which gathered approximately 210 MMcf/d of natural gas produced from 59 existing Antero horizontal Marcellus Shale wells located within the area of dedication. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion, Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant. The GGA provides CMM with a right of first offer, for seven years from closing, to acquire any future Antero midstream assets sold by Antero in an area of approximately 100,000 acres adjacent to the area of dedication that includes prospective rich gas acreage. Under the GGA, Antero will pay CMM a fixed-fee per Mcf (subject to annual escalations) for all low pressure gathering, high pressure gathering and compression services requested by Antero in the area of dedication. Additionally, as part of the GGA, Antero committed to deliver minimum annual throughput 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. This minimum volume commitment feature will provide CMM with a minimum threshold of cash flow applicable to the Antero assets each year based upon actual volumes compared to contractual minimum volume commitments for such year.

E. Marcellus Asset Company, LLC (EMAC). On December 28, 2012, CMM acquired all of the membership interests in EMAC from Enerven Compression, LLC for approximately $95 million. 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.

Our Operating Segments

We conduct all of our operations in the midstream sector with eight operating segments, four of which are reportable segments. Our operating segments reflect how we manage our operations and are reflective of primary 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 the delivery of NGLs in the United States.

As of December 31, 2012, we managed 849 miles of natural gas gathering pipelines, and NGL, gas lift, residue and production lines that range in size from four to twenty inches in diameter.

 

9


Table of Contents

Barnett:

Cowtown System. Located principally in Hood, Somervell and Johnson Counties, Texas in the southern portion of the Fort Worth Basin, the Cowtown System includes:

 

   

the Cowtown pipeline, which consists of NGL rich gas gathering systems that gather natural gas produced by our customers and delivers it to the Cowtown or Corvette plants for processing;

 

   

the Cowtown plant, which consists of two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream; and

 

   

the Corvette plant, which extracts NGLs from the natural gas stream and delivers customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream.

Residue gas from the Cowtown and Corvette plants is delivered to Atmos Energy Corporation, Enterprise Texas Pipeline LLC and/or Energy Transfer Partners, LP (Energy Transfer). Extracted NGLs from the Cowtown and Corvette plants are delivered to West Texas Pipeline, LP and Lone Star NGL LLC for delivery to Mont Belvieu, Texas. For the year ended December 31, 2012, the Cowtown and Corvette plants had a total average throughput of 132 MMcf/d of natural gas with an average NGL recovery of 17,098 Bbl/d.

The West Johnson County System was operational from the date we acquired the plant (August 24, 2012) to the date we electively ceased operating the plant (December 1, 2012). We are currently evaluating other potential uses for the West Johnson County plant, which has a processing capacity of 100 MMcf/d of natural gas.

Lake Arlington System. Located in eastern Tarrant County, Texas, the Lake Arlington System consists of a gas gathering system and related compression facility. This system gathers natural gas produced by our customers and delivers it to Energy Transfer.

Alliance System. Located in northern Tarrant and southern Denton Counties, Texas, the Alliance System consists of a gas gathering system and a related dehydration, compression and amine treating facility. This system gathers natural gas produced by our customers and delivers it to Energy Transfer and Crosstex Partners, LP (Crosstex).

Fayetteville:

Twin Groves / Prairie Creek / Woolly Hollow Systems. Located in Conway and Faulkner Counties, Arkansas, the Twin Groves/Prairie Creek/Woolly Hollow Systems consist of three gas gathering, compression, dehydration and treating facilities. These systems gather natural gas produced by BHP, BP and XTO Energy and delivers to Texas Gas Transmission, Ozark Gas Transmission and Fayetteville Express Pipeline.

Wilson Creek System. Located in Van Buren County, Arkansas, the Wilson Creek System consists of a gas gathering system and a related compression facility. This system gathers natural gas produced by independent producers and delivers to Ozark Gas Transmission.

Rose Bud System. Located in White County, Arkansas, the Rose Bud System consists of a gas gathering system and a related compression facility. This system gathers natural gas produced by XTO Energy and delivers to Ozark Gas Transmission.

Granite Wash:

Granite Wash System. Located in Roberts County, Texas, the Granite Wash System consists of:

 

   

the Indian Creek rich gas gathering system and related compression facility; and

 

   

the Indian Creek processing plant, which consists of a gas processing unit that extracts NGLs from the natural gas stream.

 

10


Table of Contents

The residue gas and extracted NGLs are delivered to unaffiliated downstream pipelines for sale. This system gathers rich natural gas produced by Chesapeake, Linn Energy, LLC and Sabine Oil and Gas LLC (Sabine) and interconnects with Mid-America Pipeline, a subsidiary of Enterprise Products Partners, L.P. for ultimate delivery of NGLs to Mont Belvieu, Texas, which historically has received premium pricing compared to the Conway NGL market. The residue gas is delivered to ANR Pipeline and Northern Natural Gas Pipeline to provide access to the Mid-Continent gas markets.

Marcellus:

Marcellus Systems. Located in Harrison and Doddridge Counties, West Virginia, the Marcellus Systems consist of low pressure gas gathering systems and compression and dehydration facilities. The Marcellus Systems interconnect with various interstate pipeline systems including Columbia, Dominion and Equitrans. The Marcellus Systems deliver high NGL content natural gas to MarkWest Energy Partners’ Sherwood Gas Processing Plant. For a further discussion of our Marcellus assets, see Acquisitions above.

Other:

Las Animas Systems. Located in Eddy County, New Mexico, the Las Animas assets consist of three gas gathering systems located in the Morrow/Atoka reservoir and the Avalon Shale rich gas trend in the Permian Basin. The Las Animas Systems include approximately 55,000 acres of dedication from Bass Oil Production Company through 2017. We believe our assets will be well positioned to benefit from future drilling in the NGL rich Avalon Shale formation.

Sabine System. Located in Sabine Parish, Louisiana, the Sabine assets consist of high-pressure gas gathering pipelines. The system provides gathering and treating services for production from Chesapeake, Comstock Resources, Inc., Forest Oil Corporation, Wildcat Sabine Pipeline LLC and Devon in the Haynesville/Bossier Shale with deliveries to Gulf South Pipeline and Tennessee Gas Pipeline Company, LLC. The Sabine System is supported by fixed-fee contracts with producers who dedicated approximately 20,000 acres to us. These contracts have initial terms through 2019 to 2021.

All of our pipelines are constructed on rights-of-way granted by the owners of the property. We have obtained, where necessary, license or permit agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, waterways, roads, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee simple.

 

11


Table of Contents

The following table lists our properties, including properties that we operate, and approximate asset capabilities as of December 31, 2012 by location:

 

     Pipeline
Miles
     Nominal Capacities (MMcfd)      Installed
Compression

(Hp)
     Compression
Units
 
        Gathering      Processing      Treating      Dehydration        

Barnett

                    

Owned

                    

Cowtown System

     298         425         425         —           425         103,590         33   

Lake Arlington System

     10         230         —           —           235         30,480         7   

Alliance System

     42         300         —           340         240         43,680         7   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Barnett - Owned

     350         955         425         340         900         177,750         47   

Operated non-owned

                    

Cowtown System

     104         —           —           —           —           —           —     

Lake Arlington System

     10         —           —           —           —           —           —     

Alliance System

     35         —           —           —           —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Barnett - Operated

     149         —           —           —           —           —           —     

Total Barnett - Owned/Operated

     499         955         425         340         900         177,750         47   

Fayetteville

                    

Twin Groves/Prairie Creek/Woolly Hollow System

     129         350         —           185         180         26,635         14   

Wilson Creek System

     24         100         —           —           5         425         1   

Rose Bud System

     15         60         —           —           5         630         1   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Fayetteville

     168         510         —           185         190         27,690         16   

Granite Wash

                    

Granite Wash System

     36         36         36         —           —           10,890         10   

Other

                    

Las Animas System

     47         50         —           —           34         —           1   

Sabine System

     57         100         —           74         72         —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total Other

     104         150         —           74         106         —           1   

Marcellus(1)

     42         420         —           —           300         43,100         31   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total

     849         2,071         461         599         1,496         259,430         105   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Represents assets owned by our unconsolidated affiliate, CMM, and that are operated by us.

Competition

The midstream energy industry is highly competitive. Competition is based on, among other things, the following:

 

   

reputation;

 

   

efficiency;

 

   

flexibility;

 

   

size;

 

12


Table of Contents
   

credit quality and reliability of the gatherer;

 

   

the pricing arrangements offered by the gatherer;

 

   

location of the gatherer’s pipeline facilities; and

 

   

the gatherer’s ability to offer a full range of services including natural gas gathering, processing, treating, compression, transportation and sales.

We believe that offering an integrated package of services allows us to compete more effectively for new natural gas supplies in our operating areas.

We face strong competition in acquiring new natural gas supplies and in pursuing acquisition opportunities as part of our long-term growth strategy. Our competitors include entities that gather, process and market natural gas. Our competitors may have capital resources and control supplies of natural gas greater than ours. Competition is typically impacted by the level of drilling activity in a particular geographic region, as well as fluctuations in commodity prices for oil, natural gas and NGLs.

Our primary competitors in the midstream industry consist of Energy Transfer, Crosstex, Eagle Rock Energy Partners, LP, Enterprise Product Partners and certain producer-owned gathering systems.

We believe that we are able to compete with these companies based on gathering and processing efficiencies, operating costs and commercial terms offered to producers, along with the location and available capacity of our gathering systems and processing plants.

Customers and Concentration of Credit Risk

Quicksilver’s production volumes accounted for approximately 48%, 59% and 86% of our total revenues for the years ended December 31, 2012, 2011 and 2010. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 5%, 5% and 7% of our total revenues for the years ended December 31, 2012, 2011 and 2010. BHP, our largest customer in our Fayetteville segment, accounted for approximately 11% of our total revenues for the year ended December 31, 2012 and approximately 9% of our total revenues for the period from acquisition (April 1, 2011) to December 31, 2011.

Although Quicksilver and BHP continue to develop their resources in counties in and around the Barnett and Fayetteville Shales, respectively, reductions in their future drilling programs could result in reduced volumes gathered, treated and processed in our facilities, if not replaced by other producers in the affected system or other system. In addition, a default in payments by Quicksilver or BHP to us for our services could have a material impact on our cash flows.

Regulatory Environment

Governmental Regulation

Regulation of our business may affect certain aspects of our operations and the market for our products and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory requirements, complaint-based rate regulation or general utility regulation. In Texas, we have filed with the Texas Railroad Commission (TRCC) to establish rates and terms of service for certain of our pipelines.

In Texas, our assets include intrastate common carrier NGL pipelines subject to the regulation of the TRCC, which requires that our NGL pipelines file tariff publications that contain all the rules and regulations governing the rates and charges for services we perform. NGL pipeline rates may be limited to provide no more than a fair return on the aggregate value of the pipeline property used to render services.

 

13


Table of Contents

Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act, or NGA, exempts natural gas gathering facilities from the jurisdiction of the Federal Energy Regulatory Commission (FERC). Our natural gas gathering activity is not subject to Internet posting requirements imposed by the FERC as a result of the FERC’s market transparency initiatives. We believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine that a pipeline is a gathering pipeline and is, therefore, not subject to the FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by the FERC, the courts or Congress. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, the FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural gas gathering may begin to receive greater regulatory scrutiny at both the state and federal levels. Our natural gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Our natural gas gathering operations are subject to ratable take and common purchaser statutes. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we currently operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

Safety and Maintenance Regulation

The pipelines we use to gather and transport natural gas and NGLs are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the Department of Transportation (DOT), pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA) with respect to natural gas and Hazardous Liquids Pipeline Safety Act of 1979, as amended, or the (HLPSA) with respect to NGLs. Both the NGPSA and the HLPSA have been amended by the Pipeline Safety Improvement Act of 2002 (PSIA) which was reauthorized and amended most recently by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas and NGL pipeline facilities, while the PSIA establishes mandatory inspections for all U.S. liquid and gas transportation pipelines and some gathering lines in high-population areas.

The PHMSA has developed regulations implementing the PSIA that require transportation pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in “high consequence areas,” such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. We, or the entities in which we own an interest, inspect our pipelines regularly in compliance with state and federal maintenance requirements.

 

14


Table of Contents

States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We do not anticipate any significant difficulty in complying with applicable state laws and regulations. Our pipelines have operations and maintenance plans designed to keep the facilities in compliance with pipeline safety requirements.

In addition, we are subject to a number of federal and state laws and regulations, including the Occupational Safety and Health Administration (OSHA) and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the OSHA hazard communication standard, the Environmental Protection Agency’s (EPA) community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and citizens.

We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, as well as the EPA’s Risk Management Program (RMP) which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds or any process which involves flammable liquid or gas in excess of 10,000 pounds. We have an internal program of inspection designed to monitor and enforce compliance with worker safety requirements. We believe that we are in material compliance with all applicable laws and regulations relating to worker health and safety.

Environmental Matters

General

Our operation of pipelines, plants and other facilities to provide midstream services is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as the following:

 

   

requiring the acquisition of various permits to conduct regulated activities;

 

   

requiring the installation of pollution-control equipment or otherwise restricting the way we can handle or dispose of our wastes;

 

   

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

   

requiring investigative and remedial actions to mitigate or eliminate pollution conditions caused by our operations or attributable to former operations; and

 

   

enjoining the operations of facilities deemed to be in non-compliance with such environmental laws and regulations and permits issued pursuant thereto.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Certain environmental statutes impose strict, and in some cases, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released; thus, we may be subject to environmental liability at our currently owned or operated facilities for conditions caused prior to our involvement.

 

15


Table of Contents

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing or future regulations.

We do not believe that compliance with current federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial condition, results of operations or cash flows. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, process, compress, treat and transport natural gas and NGLs. We can make no assurances, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. Below is a discussion of several of the material environmental laws and regulations that relate to our business. We believe that we are in material compliance with applicable environmental laws and regulations.

Hazardous Substances and Waste

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict, and in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA or Superfund law) and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons referred to as potentially responsible parties (PRPs). These PRPs include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, PRPs may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the PRPs. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14), which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA, or similar state statutes, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act (RCRA) and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

 

16


Table of Contents

We own or lease properties where hydrocarbons are being or have been handled. We have generally utilized operating and disposal practices that were standard in the industry at the time, although hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us, or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons and other wastes was not under our control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our financial condition, results of operations or cash flows.

Air Emissions

Our operations are subject to the Federal Clean Air Act (CAA), and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We believe that we are in material compliance with these requirements. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

Climate Change

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (GHG) present an endangerment to public health and the environment because emissions of such naturally occurring gases are contributing to the warming of the earth’s atmosphere and other climate changes, the EPA has adopted regulations under existing provisions of the CAA that would require a reduction in emissions of GHG from motor vehicles and also may trigger construction and operating permit review for GHG emissions from certain stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (PSD) and Title V permitting programs, pursuant to which these permitting programs have been “tailored” to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. It is widely expected that facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards for GHG that have yet to be developed. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities. With regard to the monitoring and reporting of GHG, on November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule published in October 2009 to include onshore and offshore oil and natural gas production and onshore oil and natural gas processing, transmission, storage, and distribution activities, which includes certain of our operations. In addition, the rule requires the reporting of GHG emissions for covered facilities on an annual basis beginning in 2012 for GHG emissions occurring in 2011. As of December 31, 2012, we were in compliance with the EPA rule.

Water Discharges

The Federal Water Pollution Control Act (Clean Water Act) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the U.S. and adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except

 

17


Table of Contents

in accordance with the terms of permits issued by the EPA, the Army Corps of Engineers or an analogous state agency. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. We believe that we are in material compliance with these requirements. However, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. We believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition, results of operations or cash flows.

Endangered Species

The Endangered Species Act (ESA) restricts activities that may affect endangered or threatened species or their habitats. While some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA. However, the designation of previously unidentified endangered or threatened species could cause us to incur additional costs or become subject to operating restrictions or bans in the affected states.

Anti-terrorism Measures

The Department of Homeland Security Appropriation Act of 2007 requires the Department of Homeland Security (DHS) to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to this act and, on establish chemicals of interest and their respective threshold quantities that will trigger compliance. We have determined the extent to which our facilities are subject to the rule, made the necessary notifications and determined that the requirements will not have a material impact on our financial condition, results of operations or cash flows.

Employees

Neither we nor our General Partner has any employees. Employees of Crestwood Holdings provide services to our General Partner pursuant to an Omnibus Agreement among our General Partner and Crestwood Holdings. The Omnibus Agreement terminates on the earlier of August 10, 2017 or at such time as Crestwood Holdings ceases to own or control a majority of the issued and outstanding voting securities of our General Partner.

Available Information and Corporate Governance Documents

Available Information

Our website is www.crestwoodlp.com. We make available, free of charge on or through our website, our annual report, quarterly and current reports, and any amendments to those reports, as soon as is reasonably possible after the reports are filed with the SEC. The public may also read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The public may also obtain such reports from the SEC’s Internet website at www.sec.gov.

 

18


Table of Contents

Corporate Governance Documents

Our Corporate Governance Guidelines, Code of Business Conduct and Ethics and the charters of the audit committee and the conflicts committee of our General Partner’s board of directors are also available on our Internet website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our General Partner’s corporate secretary at our principal executive office. Our principal executive offices are located at 700 Louisiana Street, Suite 2060, Houston, Texas 77002. Our telephone number is 832-519-2200.

 

Item 1A. Risk Factors

You should carefully consider the following risk factors together, with all of the other information included in this report, when deciding whether to invest in us. Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. You should be aware that the occurrence of any of the events described in this report could have a material adverse effect on our business, financial condition, results of operations and cash flows. In such event, we may not be able to make distributions to our unitholders and the trading price of our common units could decline.

Risks Related to Our Business

We are dependent on a limited number of natural gas producers, including Quicksilver, for the natural gas we gather, process, treat, compress, transport and sell. A material reduction in production by these customers would result in a material decline in our revenue and cash available for distribution.

We rely on a limited number of customers for our revenue. Our top five customers comprised approximately 85% of our total consolidated revenues in 2012. Although many of our contracts extend to 2020 and beyond, we may be unable to negotiate on favorable terms, if at all, any extension or replacement of our contracts with such customers after the term of their respective contracts expire. Our largest customer is Quicksilver. Quicksilver’s production volumes accounted for 48% of our total revenues in 2012. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised approximately 5% of our total revenues in 2012. We expect Quicksilver to continue to account for a significant portion of our revenues in 2013.

Quicksilver has no contractual obligation to develop its properties in the areas covered by their dedication to us and it may determine that it is strategically more attractive to direct its capital spending and resources to other areas. A decrease in Quicksilver’s capital spending and reserves in the areas covered by their dedication to us could result in reduced natural gas gathered and processed by us and a material decline in our revenue and cash flow.

Furthermore, the credit ratings of Quicksilver are below investment grade. Accordingly, the risk of loss resulting from any material non-payment or non-performance by Quicksilver is higher than it would be with a more creditworthy customer, especially in light of the significant concentration of business conducted with Quicksilver. Unless and until we significantly diversify our customer base, we expect to remain subject to non-diversified risk of non-payment or late payment of our fees. In addition, Quicksilver is highly leveraged and subject to its own operating and regulatory risks, which could increase the risk that it may default on its obligations to us.

We may not have sufficient available cash to enable us to make cash distributions to holders of our common units at the current distribution rate under our cash distribution policy.

In order to pay cash distributions of $0.51 per unit per quarter (based on the distribution declared in January 2013), or $2.04 per unit per year, we must generate available cash of approximately $25.1 million per quarter, or $100.4 million per year based on the number of general partner units and common units outstanding on

 

19


Table of Contents

December 31, 2012. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the announced distributions. The amount of cash we can distribute depends principally upon the amount of cash we generate from our operations, which may fluctuate from quarter to quarter based on, among other things:

 

   

the fees we charge and the margins we realize for our services;

 

   

the level of production, and the prices of, natural gas, NGLs, and condensate;

 

   

the volume of natural gas and NGLs we gather and process;

 

   

the level of competition from other midstream energy companies;

 

   

the level of our operating and maintenance and general and administrative costs;

 

   

prevailing economic conditions;

 

   

the level of capital expenditures we make;

 

   

our ability to make borrowings under our Credit Facility;

 

   

the cost of acquisitions;

 

   

our debt service requirements;

 

   

fluctuations in our working capital needs;

 

   

our ability to access capital markets;

 

   

compliance with our debt agreements; and

 

   

the amount of cash reserves established by our General Partner.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flow and not solely on profitability. Accordingly we may be prevented from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which may be affected by non-cash items. As a result, we may make cash distributions during periods when we report net losses, and conversely, we might fail to make cash distributions during periods when we report net profits.

Estimates of oil and gas reserves depend on many assumptions that may turn out to be inaccurate. Therefore, future volumes of natural gas on our systems could be less than we anticipate and could adversely affect our financial performance.

We typically do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems is less than we anticipate and we are unable to secure additional sources of natural gas, it could have a material adverse effect on our business, results of operations and financial condition.

Because of the natural decline in production from existing wells in our areas of operations, our success depends on our ability to obtain new sources of natural gas which is dependent on factors beyond our control. Any decrease in available supplies of natural gas could result in a material decline in the volumes we gather, process, treat and compress.

Our gathering systems are connected to wells whose production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our system, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our pipeline systems by our customers and our ability to compete for volumes against other midstream service providers.

 

20


Table of Contents

While we have dedications from our customers which include certain producing and non-producing oil and gas properties, we have no control over the level of drilling activity in our areas of operations, the amount of reserves associated with the wells drilled, rate at which wells are produced or the rate at which production from a well will decline. In addition, we have no control over producers’ drilling or production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations, availability of drilling rigs and other production and development services and the availability and cost of capital. Fluctuations in energy prices can greatly affect investments to develop natural gas reserves. Drilling activity generally decreases as natural gas prices decrease. Declines in natural gas prices could have a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Reductions in exploration or production activity in our areas of operations could lead to reduced utilization of our systems. Because of these factors, even if natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, our customers are not contractually obligated to develop the reserves and or properties they have dedicated to us. If reductions in drilling activity or increased competition result in our inability to obtain new sources of supply to replace the natural decline of volumes from existing wells, throughput on our systems would decline, which could reduce our revenue, cash flow and cash available for distribution to our unitholders.

In addition, various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. Hydraulic fracturing has also generated publicity regarding its potential environmental impact. The adoption of any future federal, state or local laws or regulations imposing additional permitting, disclosure or regulatory obligations related to, or otherwise restricting or increasing costs regarding the use of hydraulic fracturing could make it more difficult to drill certain oil and natural gas wells. As a result, the volume of natural gas or associated NGLs that we gather and process from wells that use hydraulic fracturing could be substantially reduced, which could adversely affect our business, financial condition, results of operations and cash available for distributions to our unitholders.

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, safety, political, legal and economic risks, which could adversely affect our cash flow, results of operations and financial condition.

One of the ways we intend to grow our business is through the construction of new midstream assets. Additions or modifications to our asset base involve numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase as anticipated for a particular project. For instance, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. Since we are not engaged in the exploration for and development of natural gas reserves, we may not have access to third party estimates of potential reserves in an area prior to constructing or acquiring facilities in such area. To the extent we rely on estimates of future production by parties in our decision to expand our systems, such estimates may prove to be inaccurate due to numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition. In addition, expansion of our asset base generally requires us to obtain new rights-of-way. We may be unable to obtain such rights-of-way or it may become more expensive for us to obtain or renew rights-of-way. If the cost of rights-of-way increases, our cash flow could be adversely affected.

If we do not make acquisitions on economically acceptable terms, our future growth will be limited.

In addition to expanding our existing systems, one of our primary strategies is to pursue acquisitions. If we are unable to make these acquisitions because we are: (1) unable to identify attractive acquisition candidates, to analyze acquisition opportunities successfully from an operational and financial point of view or to negotiate

 

21


Table of Contents

acceptable purchase contracts with them; (2) unable to obtain financing for these acquisitions on economically acceptable terms; or (3) outbid by competitors, then our future growth could be limited. Furthermore, even if we do make acquisitions, these acquisitions may not result in an increase in the cash generated by operations.

Any acquisition involves potential risks, including, among other things:

 

   

incorrect assumptions about volumes, revenues and costs, including synergies;

 

   

an inability to successfully integrate the assets we acquire;

 

   

the assumption of unknown liabilities;

 

   

limitations on rights to indemnity from the seller;

 

   

incorrect assumptions about the overall costs of equity or debt;

 

   

the diversion of management’s and employees’ attention from other business matters;

 

   

unforeseen difficulties of operating in new product areas, with new customers, or new geographic areas;

 

   

customer or key employee losses at the acquired businesses;

 

   

an inability to secure adequate customer commitments to use the acquired systems or facilities;

 

   

operating a larger combined organization and adding operations;

 

   

maintaining an effective system of internal controls related to the acquired business and integrating internal controls, compliance under the Sarbanes Oxley Act of 2002 and other regulatory compliance and corporate governance matters; and

 

   

potential environmental or regulatory compliance matters or liabilities and title issues, including certain liabilities arising from the operation of the acquired business before the acquisition

Any of the above risks could significantly impair our ability to manage our business and materially and adversely affect our business, results of operations and financial condition.

We depend on our midstream assets to generate our revenues, and if the utilization of these assets was reduced significantly, there could be a material adverse effect on our revenues, earnings and ability to make cash distributions to our unitholders.

Operations of our midstream assets could be partially curtailed or completely shut down, temporarily or permanently, as a result of:

 

   

operational problems, labor difficulties or environmental proceedings or other litigation;

 

   

catastrophic events at our facilities or at downstream facilities owned by others;

 

   

lack of transportation or fractionation capacity;

 

   

an inability to obtain sufficient quantities of natural gas; or

 

   

prolonged reductions in exploration or production activity by producers in the areas in which we operate.

The magnitude of the effect on us of any curtailment of our operations will depend on the length of the curtailment and the extent of the operations affected by such curtailment. We have no control over many of the factors that may lead to a curtailment of operations. In the event that we are unable to provide gathering, processing, treating, compression, transportation or sales services for 60 consecutive days our producers may have the right to deliver their gas to alternative pipelines. If such a termination were to occur, it could cause our revenues, earnings and cash flow to decrease.

 

22


Table of Contents

We cannot control the operations of third party NGL fractionation and natural gas and NGL transportation facilities, and our business, results of operations, financial condition and cash available for distribution could be adversely affected.

We depend upon third-party NGL transportation and fractionation systems that we do not own. Since we do not own or operate these assets, their continuing operation is not within our control. If any of these third party pipelines and other facilities becomes unavailable or capacity constrained, it could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution to our unitholders.

If one of our gas gathering agreements were to be terminated by a customer as a result of our failure to perform certain obligations under the agreement, and we were unable to secure comparable alternative arrangements, our financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders would be adversely affected.

Our gas gathering agreements are terminable if we fail to perform any of our material obligations and fail to correct such non-performance within specified periods. To the extent a customer terminates a gas gathering agreement or there is a reduction in our minimum volume commitments, our business, results of operation, financial condition and ability to make cash distributions to our unitholders may be adversely affected.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.

Our operations are generally exempt from the jurisdiction and regulation of the FERC, except that we are subject to the anti-market manipulation provisions in the Natural Gas Act, as amended by the Energy Policy Act of 2005, and to the FERC’s regulations thereunder, including the FERC’s authority to impose fines of up to $1 million per day per violation. Notwithstanding, FERC regulation still affects these businesses and the markets for products derived from these businesses. The FERC’s policies and practices across the range of its oil and natural gas regulatory activities, including, for example, its policies on open access transportation, ratemaking, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by the FERC, the courts or Congress. If our gas gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of the gathering and processing agreements with our customers.

State and municipal regulations also affect our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of our gathering lines.

 

23


Table of Contents

We are subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose us to significant costs, liabilities and obligations.

We are subject to stringent and complex federal, state and local environmental laws, regulations and permits, relating to, among other things, the generation, storage, handling, use, disposal, movement and remediation of natural gas, NGLs, crude oil and other hazardous materials; the emission and discharge of such materials to the ground, air and water; wildlife protection; and the health and safety of our employees. Failure to comply with these environmental requirements may result in our being subject to litigation, fines or other sanctions, including the revocation of permits and suspension of operations. We may incur significant compliance related costs and other associated expenses related to such requirements.

We could be liable for any environmental contamination at our or our predecessors’ currently or formerly owned or operated properties or third party waste disposal sites, regardless of whether we were at fault. In addition to potentially significant investigation and remediation costs, such matters can give rise to claims from governmental authorities and other third parties for fines or penalties, natural resource damages, personal injury and property damage.

Moreover, stricter laws, regulations or enforcement policies could significantly increase our operational or compliance costs and the cost of any remediation that may become necessary. For instance, since August 2009, the Texas Commission on Environmental Quality has conducted a series of analyses of air emissions in the Barnett Shale area in response to reported concerns about high concentrations of benzene in the air near drilling sites and natural gas processing facilities, and the analysis could result in the adoption of new air emission regulatory or permitting limitations that could require us to incur increased capital or operating costs. Additionally, environmental groups have advocated increased regulation and a moratorium on the issuance of drilling permits for new natural gas wells in developed or developing shale areas. The adoption of any laws, regulations or other legally enforceable mandates that result in more stringent air emission limitations or that restrict or prohibit the drilling of new natural gas wells for any extended period of time could increase our operating and compliance costs as well as reduce the rate of production of natural gas operators with whom the we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.

These laws, regulations and permits, and the enforcement and interpretation thereof, change frequently and generally have become more stringent over time. In particular, requirements pertaining to air emissions, including volatile organic compound emissions, have been implemented or are under development that could lead us to incur significant costs or obligations or curtail our operations. For example, GHG emission regulation has become more stringent. We are currently required to report annual GHG emissions from some of our operations, and additional GHG emission-related requirements are in various stages of development. In addition, the EPA has now begun regulating GHG emissions from stationary sources pursuant to the Prevention of Significant Deterioration and Title V provisions of the CAA. Such regulations could require us to modify existing or obtain new permits, implement additional pollution control technology, curtail operations or increase significantly our operating costs in the future. Any regulation of GHG emissions, including through a cap-and-trade or similar emissions trading schemes, technology mandate, emissions tax, reporting requirement or other program, could adversely affect our business, reputation, operating performance and product demand. In addition, to the extent climate change results in more severe weather, our customers’ operations may be disrupted, which could reduce product demand.

In addition, various federal and state initiatives are underway to regulate, or further investigate the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formations to stimulate hydrocarbon production. To the extent these initiatives reduce the volume of natural gas or associated NGLs that we gather and process, they could adversely affect our business.

Our costs, liabilities and obligations relating to environmental matters could have a material adverse effect on our business, reputation, results of operations and financial condition.

 

24


Table of Contents

We may incur costs as a result of pipeline integrity management program testing.

The DOT requires pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could harm “high consequence areas.” The regulations require operators, including us, to:

 

   

perform ongoing assessments of pipeline integrity;

 

   

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

   

maintain processes for data collection, integration and analysis;

 

   

repair and remediate pipelines as necessary; and

 

   

implement preventive and mitigating actions.

We currently estimate that we will incur total future costs of approximately $1 million through 2016 to complete the testing required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program itself.

We may incur costs as a result of additional pipeline safety legislation.

The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 was enacted by Congress in December 2011 and signed into law by the President on January 3, 2012. In addition to reauthorizing federal pipeline safety programs through 2015, this legislation adopts additional safety requirements and reforms and increases penalties for safety violations. The PHMSA has also published an advanced notice of proposed rulemaking to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in our business or our industry and place us at a competitive disadvantage.

We had approximately $558 million of long-term debt outstanding as of December 31, 2012. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, results of operations, financial condition and business prospects.

Our substantial debt could have important consequences to our unitholders. For example, it could:

 

   

increase our vulnerability to general adverse economic and industry conditions;

 

   

limit our ability to fund future capital expenditures and working capital, to engage in development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive covenants or terms of our debt;

 

   

result in an event of default if we fail to satisfy our obligations with respect to our indebtedness or fail to comply with the financial and other restrictive covenants contained in the agreements governing our indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of the collateral securing such debt;

 

   

in the event of default or a default being created by a distribution, we will be prohibited to declare or pay a distribution;

 

25


Table of Contents
   

require a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use our cash flow to fund our operations, capital expenditures and future business opportunities;

 

   

increase our cost of borrowing;

 

   

restrict us from making strategic acquisitions or causing us to make non-strategic divestitures;

 

   

limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our peers who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring; and

 

   

impair our ability to obtain additional financing in the future.

Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.

If we are unable to obtain needed capital or financing on satisfactory terms, our ability to make cash distributions may be diminished and our financial leverage could increase.

Historically, we have used our cash flow from operations, borrowings under our Credit Facility and issuances of equity to fund our capital program, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund our growth. If our cash flow from operations decreases as a result of lower throughput volumes on our gathering and processing systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations is insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms or at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operation, financial condition and ability to make cash distributions to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make payments on our debt obligations.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Therefore, changes in interest rates either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations.

We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. We obtain standard easement rights to construct and operate our pipelines on land owned by third parties. Our rights generally revert back to the landowner after we stop using the easement for its specified purpose.

 

26


Table of Contents

Therefore, these easements exist for varying periods of time. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our revenue, earnings and ability to make cash distributions to our unitholders.

Our business involves many hazards and operational risks, some of which may not be adequately covered by insurance. The occurrence of a significant accident or other event that is not adequately insured could curtail our operations and have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Our operations are subject to many risks inherent in the midstream industry including:

 

   

damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism;

 

   

inadvertent damage from construction, farm and utility equipment;

 

   

leaks or losses of natural gas or NGLs as a result of the malfunction of equipment or facilities;

 

   

fires and explosions;

 

   

cyber intrusions; and

 

   

other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.

These risks could result in curtailment or suspension of our related operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. Hostile cyber intrusions, including those targeting sensitive customer information, employee and vendor information maintained by us in the normal course of business, as well as breaches in the technology used in our business processes, could severely disrupt business operations and result in loss of service to customers, as well as significant expense to repair security breaches or system damage We maintain insurance against some, but not all, of such risks and losses in accordance with customary industry practice. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental incidents, claims or damages that might occur. Any significant accident or event that is not adequately insured could adversely affect our business, results of operations and financial condition. In addition, we may be unable to economically obtain or maintain the insurance that we desire. As a result of market conditions, premiums and deductibles for certain of our insurance policies could escalate further. In some instances, certain insurance could become unavailable or available only at reduced coverage levels. Any type of catastrophic event could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

The loss of key personnel could adversely affect our ability to operate.

Our success is dependent upon the efforts of our senior management, as well as on our ability to attract and retain senior management. Our senior executive officers have significant experience in the natural gas industry and have developed strong relationships with a broad range of industry participants. The loss of any of these executives could prevent us from implementing our business strategy and have a material adverse effect on our relationships with these industry participants, our results of operations and ability to make cash distributions to our unitholders.

We do not have employees. We rely solely on officers and employees of Crestwood Holdings to operate and manage our business.

 

27


Table of Contents

Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.

We compete with similar enterprises in our area of operation. Our competitors may expand or construct gathering systems and associated infrastructure that would create additional competition for the services we provide our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We may conduct certain operations through joint ventures that may limit our operational flexibility.

Prior to January 8, 2013, our operations in the Marcellus Shale region were conducted through joint venture arrangements, and we may enter additional joint ventures in the future. In a joint venture arrangement, we could have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases:

 

   

we could have limited ability to influence or control certain day to day activities affecting the operations;

 

   

we could have limited control on the amount of capital expenditures that we are required to fund with respect to these operations;

 

   

we could be dependent on third parties to fund their required share of capital expenditures;

 

   

we may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and

 

   

we may be forced to offer rights of participation to other joint venture participants in certain areas of mutual interest.

In addition, our joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance and ability of the third parties to satisfy their obligations under joint venture arrangements is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.

We are currently solely reliant on the performance of our midstream business and assets, and as a result of this lack of diversification, our ability to make distributions to our unitholders could be adversely impacted.

Given the concentration inherent in our business, in that it is entirely reliant on the revenues and cash flows generated from our midstream business and its assets, any adverse developments in the midstream energy industry could impact our ability to generate sufficient cash flows, which could affect the level of distributions to our unitholders.

 

28


Table of Contents

If we fail to maintain effective internal control over financial reporting, we may have material misstatements in our financial statements, and we may not be able to report our financial results in a timely and reliable manner.

We have established internal controls over financial reporting. However, internal controls over financial reporting may not prevent or detect misstatements because of their inherent limitations, including the possibility of human error, the circumvention or overriding of controls or fraud. Therefore, even effective internal controls can provide only reasonable assurance with respect to the preparation and fair presentation of financial statements. If we fail to maintain the adequacy of our internal controls, we may be unable to provide financial information in a timely and reliable manner. Any such difficulties or failure may have a material adverse effect on our business, financial condition and operating results.

During the course of the preparation of our financial statements, we evaluate our internal controls to identify and remediate deficiencies in our internal controls over financial reporting. In the event we are unable to identify and correct deficiencies in our internal controls in a timely manner, we may not record, process, summarize and report financial information accurately and within the time periods required for our financial reporting under the terms of the agreements governing our indebtedness or within the required deadlines established by the SEC.

Failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities, cause unitholders to lose confidence in our reported financial condition, lead to a default under our Credit Facility and otherwise materially adversely affect our business, financial condition and results of operations.

Risks Inherent to an Investment in Us

Crestwood Holdings owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations. Crestwood Holdings and our General Partner have conflicts of interest with, and may favor, Crestwood Holdings’ interests to the detriment of our unitholders.

Crestwood Holdings owns and controls our General Partner, and appoints all of the directors of our General Partner. Some of our General Partner’s directors, and some of its executive officers, are directors or officers of Crestwood Holdings or its affiliates. Although our General Partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to Crestwood Holdings. Therefore, conflicts of interest may arise between Crestwood Holdings and its affiliates, including our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over the interests of our unitholders.

Crestwood Holdings is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

Crestwood Holdings is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, in the future, Crestwood Holdings may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities. Moreover, while Crestwood Holdings may offer us the opportunity to buy assets from it or to participate in investments with it, it is under no contractual obligation to do so and we are unable to predict whether or when such acquisitions might be completed.

 

29


Table of Contents

Cost reimbursements due to Crestwood Holdings and our General Partner for services provided to us or on our behalf will be substantial and will reduce our cash available for distribution to our unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to making distributions on our common units, we will reimburse our General Partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by Crestwood Holdings and our General Partner in managing and operating us. Our Second Amended and Restated Agreement of Limited Partnership of CMLP, dated February 19, 2008, as amended (Partnership Agreement) provides that our General Partner will determine in good faith the expenses that are allocable to us. The reimbursements to Crestwood Holdings and our General Partner will reduce the amount of cash otherwise available for distribution to our unitholders.

If you are not an eligible holder, you may not receive distributions or allocations of income or loss on your common units, and your common units will be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S. individuals or entities subject to such taxation. If you are not an eligible holder, our General Partner may elect not to make distributions or allocate income or loss on your units and you run the risk of having your units redeemed by us at the lower of your purchase price cost and the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our General Partner.

Our General Partner’s liability regarding our obligations is limited.

Our General Partner included provisions in its and our contractual arrangements that limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our Partnership Agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments may adversely affect our business, results of operations and financial condition and would reduce the amount of cash otherwise available for distribution to our unitholders.

Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per-unit distribution level. There are no limitations in our Partnership Agreement or in Crestwood Holdings’ credit facility, on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may adversely affect our business, results of operations and financial condition and impact the available cash that we have to distribute to our unitholders.

 

30


Table of Contents

Our General Partner may elect to cause us to issue Class B and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the special committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

Our General Partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48% for each of the prior four consecutive fiscal quarters), to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our General Partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our General Partner elects to reset the target distribution levels, it will be entitled to receive a number of Class B units and general partner units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued to our General Partner will be equal to that number of common units which would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our General Partner on the incentive distribution rights in the prior two quarters. Our General Partner will be issued the number of general partner units necessary to maintain an interest in us, equivalent to the interest that existed immediately prior to the reset election. We anticipate that our General Partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our General Partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued Class B units, which are entitled to distributions on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new Class B units and general partner units to our General Partner in connection with resetting the target distribution levels.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our General Partner or its board of directors. The board of directors of our General Partner is chosen by the sole member of Crestwood Gas Services Holdings LLC. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Even if holders of our limited partner units are dissatisfied, they cannot initially remove our General Partner without its consent.

The unitholders initially will be unable to remove our General Partner without its consent because our General Partner and its affiliates currently own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our General Partner. As of December 31, 2012, the General Partner and Crestwood Holdings beneficially owned 39.8% of our outstanding limited partner units. As of February 14, 2013, the General Partner and Crestwood Holdings beneficially owned 46.3% of our limited partner units.

 

31


Table of Contents

Our Partnership Agreement restricts the voting rights of certain unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our Partnership Agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our General Partner, cannot vote on any matter.

Our General Partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its General Partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of Crestwood Holdings to transfer all or a portion of its ownership interest in our General Partner to a third party. In such a case, the new owner of our General Partner would then be in a position to replace the board of directors and officers of our General Partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

We may issue additional units without unitholder approval, which would dilute existing ownership interests.

Our Partnership Agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

our existing unitholders’ proportionate ownership interest in us will decrease;

 

   

the amount of cash available for distribution on each unit may decrease;

 

   

the ratio of taxable income to distributions may increase;

 

   

the relative voting strength of each previously outstanding unit may be diminished; and

 

   

the market price of the common units may decline.

Crestwood Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of December 31, 2012, Crestwood Holdings beneficially held an aggregate of 19,544,089 common units. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which common units are traded.

Our General Partner has a limited call right that may require existing unitholders to sell their units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of the common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price. As a result, existing unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Existing unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2012, the General Partner and Crestwood Holdings beneficially owned 39.8% of our outstanding limited partner units. As of February 14, 2013 the General Partner and Crestwood Holdings beneficially owned 46.3% of our limited partner units.

 

32


Table of Contents

Unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states. A unitholder could be liable in some circumstances for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:

 

   

we were conducting business in a state but had not complied with the applicable limited partnership statute; or

 

   

unitholder’s right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our partnership agreement constitute “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The market price of our common units could be volatile due to a number of factors, many of which are beyond our control.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including, changes in securities analysts’ recommendations; public’s reaction to our press releases, announcements and our filings with the SEC; fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly-traded limited partnerships; changes in market valuations of similar companies; departures of key personnel; commencement of or involvement in litigation; variations in our quarterly results of operations or those of midstream companies; variations in the amount of our quarterly cash distributions; future issuances and sales of our common units; availability of, and sufficient access to, capital; and changes in general conditions in the U.S. economy, financial markets or the midstream industry.

Tax Risks to Common Unitholders

Our tax treatment depends on our being treated as a partnership for federal income tax purposes, as well as our not being subject to a material amount of additional entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation or if we become subject to a material amount of additional entity-level taxation for state tax purposes, then it would substantially reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated

 

33


Table of Contents

as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations that we will be so treated, the Internal Revenue Service (IRS), could disagree with positions we take or a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits recognized by us would flow through to our unitholders. If we were treated as a corporation at the state level, we would likely also be subject to entity-level state income tax at varying rates.

Moreover, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation.

The imposition of any entity-level taxation, including a federal income tax imposed on us as a corporation or any entity-level state taxes, will reduce the amount of cash we can distribute each quarter to the holders of our common units. Therefore, our treatment as a corporation for federal income tax purposes or becoming subject to a material amount of additional state taxes could result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly-traded partnerships. One such legislative proposal would eliminate the qualifying income exemption upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income, adversely affect an investment in our common units or otherwise negatively impact the value of an investment in our common units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

34


Table of Contents

An Internal Revenue Service challenge of the federal income tax positions we have taken or may take may adversely affect the market for our common units, and the cost of any Internal Revenue Service challenge will reduce our cash available for distribution to our unitholders.

We have not requested any ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we have taken or may take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we have taken or may take. A court may not agree with some or all the positions we have taken or may take. Any challenge with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any challenge with the IRS will result in a reduction in cash available to pay distributions to our unitholders and our General Partner and thus will be borne indirectly by our unitholders and our General Partner.

Unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than cash we distribute, they will be required to pay federal income taxes and, in some cases, state, local and foreign income taxes on their allocable share of our taxable income, whether or not cash is distributed from us. Cash distributions may not equal a unitholder’s share of our taxable income or even equal the actual tax liability that results from the unitholder’s allocable share of our taxable income.

The tax gain or loss on the disposition of our common units could be different than expected.

If our unitholders sell units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions to them in excess of the total net taxable income they were allocated for a common unit, which decreased their tax basis in that common unit, will, in effect, become taxable income to them if the common unit is sold at a price greater than their tax basis in that common unit, even if the price they receive is less than their original cost. A substantial portion of the amount realized, regardless of whether such amount represents gain, may be taxed as ordinary income to our unitholders due to potential recapture items, including depreciation recapture. In addition, if they sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (IRAs) Keogh plans and other retirement plans, regulated investment companies, real estate investment trusts, mutual funds and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. Tax-exempt entities or foreign persons should consult their tax advisor regarding their investment in our common units.

We will treat each purchaser of units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could result in a unitholder owing more tax and could otherwise adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax

 

35


Table of Contents

return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from their sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to their tax returns.

We may adopt certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the general partner and the unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our General Partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our methodologies, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50 percent or more of our capital and profits interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal tax purposes. If treated as a new partnership for federal tax purposes, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

Unitholders may become subject to state and local taxes and return filing requirements in states where they do not live as a result of their investment in our common units.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose an income tax. It is the unitholder’s responsibility to file all required federal, foreign, state and local tax returns.

 

36


Table of Contents

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units, such unitholder may no longer be treated as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

 

37


Table of Contents
Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

A description of our properties is included in Item 1. Business, and is incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used in our business, subject to liens for taxes not yet payable, liens incident to minor encumbrances, liens for credit arrangements and easements and restrictions that do not materially detract from the value of these properties, our interests in these properties or the use of these properties in our business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

 

Item 3. Legal Proceedings

A description of our legal proceedings is included in Part II, Item 8. Financial Statements and Supplementary Data, Note 11. Commitments and Contingent Liabilities, and is incorporated herein by reference.

 

Item 4. Mine Safety Disclosures

Not Applicable.

 

38


Table of Contents

PART II

 

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchase of Equity Securities

Market Information

Our common units are currently traded on the NYSE under the symbol “CMLP.” The following table sets forth the high and low sales prices of our common units and the per unit distributions paid for the periods indicated below and are recorded when paid.

 

Quarter Ended

   High      Low      Distributions
Per Common
Unit
     Record Date      Payment Date  

2011

              

March 31, 2011

   $ 31.78       $ 27.00       $ 0.44         May 3, 2011         May 13, 2011   

June 30, 2011

   $ 33.00       $ 26.50       $ 0.46         Aug. 2, 2011         Aug. 12, 2011   

September 30, 2011

   $ 28.15       $ 21.72       $ 0.48         Nov. 1, 2011        Nov. 10, 2011   

December 31, 2011

   $ 32.58       $ 22.00       $ 0.49         Jan. 31, 2012         Feb. 10, 2012   

2012

              

March 31, 2012

   $ 32.45       $ 27.50       $ 0.50         May 1, 2012         May 11, 2012   

June 30, 2012

   $ 29.24       $ 24.13       $ 0.50         Aug. 2, 2012         Aug. 10, 2012   

September 30, 2012

   $ 29.12       $ 22.11       $ 0.51         Oct. 30, 2012         Nov. 9, 2012   

December 31, 2012

   $ 24.50       $ 19.90       $ 0.51         Jan. 31, 2013         Feb. 12, 2013   

The last reported sale price of our common units on the NYSE on February 14, 2013, was $26.16. As of that date, we had 15 holders of record of our common units, including Cede & Co., as nominee for the Depository Trust Company, which held of record 21,621,052 common units. As of February 14, 2013, we have also issued and outstanding 7,349,814 Class C units, which were held of record by 16 holders, issued and outstanding 6,190,469 Class D units, which were held by Crestwood Holdings, and 1,112,674 general partner units.

Distribution of Available Cash

General. Our Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, as determined by our General Partner.

Definition of Available Cash. The term “available cash,” for any quarter, consists of all cash on hand at the end of that quarter:

 

   

less the amount of cash reserves established by our General Partner to:

 

   

comply with applicable law, any of our debt instruments or other agreements; or

 

   

provide funds for distribution to our unitholders and to our General Partner for any one or more of the next four quarters;

 

   

plus, if our General Partner so determines, all or a portion of cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter; and

 

   

plus, if our General Partner so determines, all or a portion of available working capital borrowings on the date of determination of available cash for such quarter.

Working capital borrowings are generally borrowings that are made under a Credit Facility or another arrangement, are used solely for working capital purposes or to pay distributions to unitholders and are intended to be repaid within 12 months. Available working capital borrowings means, on the date of determination, any amounts available to be borrowed as working capital borrowings.

 

39


Table of Contents

Minimum Quarterly Distribution. We intend to distribute to the holders of common units on a quarterly basis at least the minimum quarterly distribution of $0.30 per unit, or $1.20 per year, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement. We will be prohibited from making any distributions to unitholders if it would cause an event of default or an event of default exists, under our Credit Facility (or indentures).

General Partner Interest and Incentive Distribution Rights. Our General Partner is currently entitled to 2% of all quarterly distributions that we make prior to our liquidation. As of December 31, 2012 our General Partner interest is 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 2% interest in these 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 2% general partner interest.

Our General Partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, 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 on its 2% general partner interest and assumes that our General Partner maintains its general partner interest at 2%. 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 illustrates the percentage allocations of available cash from operating surplus between the unitholders and our General Partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our General Partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for the unitholders and the General Partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our General Partner include its 2% general partner interest and assume our General Partner has contributed any additional capital to maintain its 2% general partner interest and has not transferred its incentive distribution rights.

 

     Total Quarterly
Distribution Per Unit

Target Amount
   Marginal Percentage
Interest  in
Distributions*
 
        Unitholders     General Partner  

Minimum Quarterly Distribution

   $0.3000      98     2

First Target Distribution

   up to 0.3450      98     2

Second Target Distribution

   above 0.3450 up to 0.3750      85     15

Third Target Distribution

   above 0.3750 up to 0.4500      75     25

Thereafter

   above 0.4500      50     50

 

* Assuming there are no arrearages on common units and that our General Partner maintains its 2% general partner interest and continues to own the incentive distribution rights.

 

40


Table of Contents

Performance Graph

The following performance graph compares the cumulative total unitholder return of our common units with the Standard & Poor’s 500 Stock Index (“S&P 500”) and the Alerian MLP Index for the period from our initial public offering (August 7, 2007) to December 31, 2012, assuming an initial investment of $100 and reinvestment of all subsequent distributions or dividends, as applicable.

Comparison of Cumulative Total Return

 

LOGO

 

41


Table of Contents
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 and 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 Annual Report on Form 10-K.

 

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

Statement of Income Data:

             

Operating revenues

   $ 213,961       $ 205,820       $ 113,590       $ 95,881      $ 76,084   

Operating income

     62,723         73,871         47,872         43,408        37,151   

Income before income taxes

     32,952         46,254         34,322         34,890        28,725   

Net income from continuing operations

     31,746         45,003         34,872         34,491        28,472   

Loss from discontinued operations

     —           —           —           (1,992     (2,330

Net income

     31,746         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)

     217,914         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)

   $ 112,296       $ 107,683       $ 70,231       $ 64,238      $ 50,293   

Adjusted EBITDA (4)

     119,328         109,962         76,549         64,238        50,293   

Balance Sheet Data:

             

Property, plant and equipment, net

   $ 784,371       $ 746,045       $ 531,371       $ 482,497      $ 441,863   

Total assets

     1,233,407         1,026,892         570,627         487,624        502,606   

Long-term debt

     558,161         512,500         283,504         125,400        174,900   

Other long-term obligations (5)

     16,349         15,474         9,877         62,162        123,928   

Partners’ capital

     620,695         455,623         258,753         284,837        115,208   

 

(1) 

In January 2010, we acquired from 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.

 

42


Table of Contents
(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. Additionally, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliate by adjusting our equity earnings from our unconsolidated affiliate for our proportionate share of its depreciation and amortization, interest and other significant items for 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.

 

43


Table of Contents
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 (described further in Part I, Item 1A. Risk Factors) that may result in actual results differing from the statements we make.

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 48%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 5%, 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:

 

44


Table of Contents

(i) the Cowtown System; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems acquired by Crestwood Marcellus Midstream LLC (CMM, our unconsolidated affiliate), in the Marcellus segment. For the year ended December 31, 2012, our consolidated systems (i.e., excluding CMM) located in NGL rich gas basins contributed approximately 56% of our total revenues and 32% of our total gathering volumes. For the year ended December 31, 2012, our consolidated and unconsolidated systems that we operate located in NGL rich gas basins (i.e., including 100% of CMM’s results), when combined, would have contributed approximately 61% of our total consolidated and unconsolidated revenues and 51% of total consolidated and unconsolidated 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. Additionally, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliate by adjusting our equity earnings from our unconsolidated affiliate for our proportionate share of its depreciation, amortization and accretion, interest and other significant items for 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.

 

 

45


Table of Contents

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 acquisition from Devon Energy Corporation (Devon). Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain. The recent acquisition of our additional interest in CMM along with CMM’s acquisition of EMAC in December 2012 will substantially increase our exposure to the rich gas area of the Marcellus Shale region and will be an integral component of our growth-oriented business model.

Our consolidated systems gathered 595 MMcf/d for the year ended December 31, 2012 which is an increase of 4% from 2011 and 73% 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 4% increase in our overall revenues from 2011 and 88% from 2010. From March 2012 to December 31, 2012, CMM, our unconsolidated affiliate, gathered 302 MMcf/d.

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

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.

CMM Investment

On March 26, 2012, we invested approximately $131 million in cash in exchange for a 35% interest in CMM, which is held by our wholly-owned subsidiary. Crestwood Holdings LLC and its affiliates (Crestwood Holdings)

 

46


Table of Contents

invested $244 million for the remaining 65% interest. CMM was formed to acquire certain of Antero Resources Appalachian Corporation’s (Antero) Marcellus Shale gathering system assets located in Harrison and Doddridge Counties, West Virginia. CMM’s purchase price to acquire the assets was approximately $380 million.

In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $129 million in cash, 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 our acquisition of the additional membership interest, CMM became our wholly-owned consolidated subsidiary.

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.

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.

The assets acquired by CMM consist of a 33 mile low pressure gathering system which gathered approximately 210 MMcf/d from 59 existing horizontal Marcellus Shale wells. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion, Equitrans and Mark West Energy Partners’ Sherwood Gas Processing Plant.

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 15. Partners’ Capital.

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 Credit Facility.

 

47


Table of Contents

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

   $ 213,961      $ 205,820      $ 113,590   

Product purchases

     39,005        38,787        —     

Operations and maintenance expense

     40,617        36,303        25,702   

General and administrative expense

     25,890        24,153        17,657   

Depreciation, amortization and accretion

     45,726        33,812        22,359   

Gain from exchange of property, plant and equipment

     —          1,106        —     
  

 

 

   

 

 

   

 

 

 

Operating income

     62,723        73,871        47,872   

Earnings from unconsolidated affiliate

     3,847        —          —     

Interest and debt expense

     33,618        27,617        13,550   

Income tax expense (benefit)

     1,206        1,251        (550
  

 

 

   

 

 

   

 

 

 

Net income

   $ 31,746      $ 45,003      $ 34,872   

Add:

      

Interest and debt expense

     33,618        27,617        13,550   

Income tax expense

     1,206        1,251        (550

Depreciation, amortization and accretion expense

     45,726        33,812        22,359   
  

 

 

   

 

 

   

 

 

 

EBITDA

   $ 112,296      $ 107,683      $ 70,231   

Expenses associated with significant items

     3,805        3,385        6,318   

Gain from exchange of property, plant and equipment

     —          (1,106     —     

Earnings from unconsolidated affiliate

     (3,847     —          —     

Adjusted earnings from unconsolidated affiliate

     7,074        —          —     
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

   $ 119,328      $ 109,962      $ 76,549   
  

 

 

   

 

 

   

 

 

 

 

48


Table of Contents

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

 

    Year Ended December 31,  
    Barnett     Fayetteville     Granite Wash     Other     Total  
    2012     2011     2012     2011     2012     2011     2012     2011     2012     2011  

Gathering revenues

  $ 98,889      $ 108,705      $ 26,986      $ 19,421      $ 1,434      $ 346      $ 10,202      $ 2,483      $ 137,511      $ 130,955   

Processing revenues

    34,003        31,379        —          —          130        133        —          —          34,133        31,512   

Product sales

    141        —          512        1,379        38,992        37,734        2,672        4,240        42,317        43,353   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

  $ 133,033      $ 140,084      $ 27,498      $ 20,800      $ 40,556      $ 38,213      $ 12,874      $ 6,723      $ 213,961      $ 205,820   

Product purchases

    125        —          523        1,302        35,695        33,245        2,662        4,240        39,005        38,787   

Operations and maintenance expense

    26,881        25,147        8,537        8,992        2,250        1,499        2,949        665        40,617        36,303   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

EBITDA(1)

  $ 106,027      $ 114,937      $ 18,438      $ 10,506      $ 2,611      $ 3,469      $ 7,263      $ 1,818       
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

Gathering volumes (in MMcf)

    158,087        172,838        31,617        23,421        6,440        4,555        21,770        7,332        217,914        208,146   

Processing volumes (in MMcf)

    56,844        48,112        —          —          6,420        4,501        —          —          63,264        52,613   

 

(1)      EBITDA in this table excludes earnings from our unconsolidated affiliate which represents our Marcellus segment.

          

    Year Ended December 31,  
    Barnett     Fayetteville     Granite Wash     Other     Total  
    2011     2010     2011     2010     2011     2010     2011     2010     2011     2010  

Gathering revenues

  $ 108,705      $ 83,394      $ 19,421      $ —        $ 346      $ —        $ 2,483      $ —        $ 130,955      $ 83,394   

Processing revenues

    31,379        30,196        —          —          133        —          —          —          31,512        30,196   

Product sales

    —          —          1,379        —          37,734        —          4,240        —          43,353        —     
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total operating revenues

  $ 140,084      $ 113,590      $ 20,800      $ —        $ 38,213      $ —        $ 6,723      $ —        $ 205,820      $ 113,590   

Product purchases

    —          —          1,302        —          33,245        —          4,240        —          38,787        —     

Operations and maintenance expense

    25,147        25,702        8,992        —          1,499        —          665        —          36,303        25,702   
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

EBITDA

  $ 114,937      $ 87,888      $ 10,506      $ —        $ 3,469      $ —        $ 1,818      $ —         
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

     

Gathering volumes (in MMcf)

    172,838        125,317        23,421        —          4,555        —          7,332        —          208,146        125,317   

Processing volumes (in MMcf)

    48,112        46,660        —          —          4,501        —          —          —          52,613        46,660   

EBITDA and Adjusted EBITDA — EBITDA for the year ended December 31, 2012 was approximately $112 million, an increase of approximately $5 million from 2011 and approximately $42 million from 2010. In the same manner, Adjusted EBITDA for the year ended December 31, 2012 was approximately $119 million, an increase of approximately $10 million from 2011 and approximately $42 million from 2010. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities, which was approximately $3 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, gains on the exchange of property, plant and equipment, which was approximately $1 million at December 31, 2011 and includes approximately $3 million of net earnings adjustments related to adding back our proportionate share of our unconsolidated affiliate’s depreciation and amortization expense, interest and debt expense and expenses related to their significant items for the year ended December 31, 2012.

 

49


Table of Contents

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.

 

50


Table of Contents

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.

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.

Marcellus:

In March 2012, we invested approximately $131 million in cash for a 35% ownership interest in CMM. At the same time, CMM purchased assets in the Marcellus Shale from Antero. This investment in CMM, which was an unconsolidated affiliate at December 31, 2012, represents our Marcellus segment.

For the period from March 26, 2012 to December 31, 2012, we had approximately $3.8 million in earnings from our unconsolidated affiliate. The increased equity earnings in our unconsolidated affiliate during the period from March 26, 2012 to December 31, 2012 were primarily due to the increase in volumes from the wells that were connected to CMM since its inception. CMM gathered 302 MMcf/d through its assets acquired from Antero. Since the inception of CMM, Antero connected 49 wells to CMM.

On December 28, 2012, CMM completed the acquisition of 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 and Doddridge Counties, West Virginia. The assets will provide compression and dehydration services to Antero under a compression services agreement through 2018.

 

51


Table of Contents

In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $129 million in cash, 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 our acquisition of the additional membership interest, CMM became our wholly-owned consolidated subsidiary during the first quarter of 2013.

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 $1.7 million when compared 2011. General and administrative expense includes costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $3.8 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 Credit Facility; (ii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012; and (iii) 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 Facility and Senior Notes, see Item 8. Financial Statements and Supplementary Data, Note 6. Financial Instruments.

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

 

                                                                          
     Year Ended December 31,  
     2012     2011     2010  

Credit Facility

   $ 15,423      $ 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

     33,909        27,816        13,550   

Less capitalized interest

     (291     (199     —     
  

 

 

   

 

 

   

 

 

 

Total interest and debt costs

   $ 33,618      $ 27,617      $ 13,550   
  

 

 

   

 

 

   

 

 

 

Liquidity and Capital Resources

Our sources of liquidity include cash flows generated from operations, available borrowing capacity under our Credit Facility, and issuances of additional debt and equity in the capital markets. We believe that our

 

52


Table of Contents

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 Facility and debt or equity offerings to finance the majority of our long-term growth capital expenditures or acquisitions.

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

Known Trends and Uncertainties Impacting Liquidity

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

 

   

Concentration of Gathering Revenues from Quicksilver: 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, 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 48%, 59% and 86% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni Spa, which comprised 5%, 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: Our borrowings under the Credit Facility were $207 million as of December 31, 2012 and based on our results through December 31, 2012, our remaining available capacity under the Credit Facility was $167 million. While we anticipate that our current available borrowing capacity under our Credit Facility 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 $418 million, $500 million and $91 million through debt and equity offerings and increases to our Credit Facility to fund acquisitions and growth capital projects. In January 2013, we borrowed $129 million under our 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

 

53


Table of Contents
 

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 acquired by CMM (our unconsolidated affiliate), in the Marcellus segment. For the year ended December 31, 2012, these rich gas systems accounted for approximately 61% of our total consolidated and unconsolidated 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

   $ 89,267      $ 86,331      $ 48,003   

Net cash used in investing activities

     (251,366     (456,535     (149,345

Net cash provided by financing activities

     161,323        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 $89 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 Devon Acquisition in August 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 Facility 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

 

54


Table of Contents

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 Facility 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 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 acquisition of 35% interest in CMM for approximately $131 million;

 

   

Distributions from CMM of approximately $3 million;

 

   

The Devon Acquisition for approximately $87 million; and

 

   

Capital expenditures of approximately $36 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

 

55


Table of Contents
   

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 Credit Facility of $106 million in 2012;

 

   

Net borrowings under our 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 $92 million, which increased by $28 million when compared to 2011 and $42 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

   $ —         $ —         $ 206,700       $ 351,461       $ 558,161   

Interest

     21,308         42,617         41,907         19,375         125,207   

Operating lease obligations

     936         1,126         161         15         2,238   

Capital lease obligations

     4,020         3,135         219         —           7,374   

Asset retirement obligations

     —           —           —           13,188         13,188   

Other contractual liabilities and purchase obligations

     2,831         —           —           —           2,831   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual obligations

   $ 29,095       $ 46,878       $ 248,987       $ 384,039       $ 708,999   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

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

 

56


Table of Contents

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 $5.8 million annually on our Credit Facility. For each additional $10 million in borrowings, annual interest payments will increase by approximately $0.3 million. If the committed amount under our Credit Facility would have been fully utilized at December 31, 2012 at interest rates in effect at that time, annual interest expense would increase by approximately $9.6 million. If interest rates on our December 31, 2012 variable debt balance of $206.7 million increase or decrease by one percentage point, our annual income will decrease or increase by $2.1 million related to interest expense. For a further discussion of our debt obligations, see Item 8. Financial Statements and Supplementary Data, Note 6. Financial Instruments.

Operating Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 11. Commitments and Contingent Liabilities.

Capital Leases. For a further discussion of these obligations, see Item 8. Financial Statements and Supplementary Data, Note 11. 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 11. 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 $39 million of our accounts receivable which was primarily due from 10 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

 

57


Table of Contents

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.

 

58


Table of Contents

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.

 

59


Table of Contents
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 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.

 

60


Table of Contents
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  

Management’s Annual Report on Internal Control over Financial Reporting

     62   

Reports of Independent Registered Public Accounting Firm

     63   

Consolidated Statements of Income

     65   

Consolidated Balance Sheets

     66   

Consolidated Statements of Cash Flows

     67   

Consolidated Statements of Changes in Partners’ Capital

     68   

Notes to Consolidated Financial Statements

     69   

Supplemental Financial Information

  

Supplemental Selected Quarterly Financial Information (Unaudited)

     92   

 

61


Table of Contents

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONROL OVER FINANCIAL REPORTING

Management of our General Partner, under the supervision and with the participation of our General Partner’s Chief Executive Officer and Interim Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with United States generally accepted accounting principles. It consists of policies and procedures that:

 

   

Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

 

   

Provide reasonable assurance that the transactions are recorded as necessary to permit preparation of the financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management; and

 

   

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

Under the supervision and with the participation of our General Partner’s Chief Executive Officer and Interim Chief Financial Officer, our General Partner’s management made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, our General Partner’s management has concluded that our internal control over financial reporting was effective as of December 31, 2012. The effectiveness of our internal control over financial reporting as of December 31, 2012 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report included herein.

 

62


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Crestwood Midstream Partners LP

We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners LP and subsidiaries (the “Partnership”) as of December 31, 2012 and 2011, and the related 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 financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these 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 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.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2013, expressed an unqualified opinion on the Partnership’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2013

 

63


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Unitholders of

Crestwood Midstream Partners LP

We have audited the internal control over financial reporting of Crestwood Midstream Partners LP and subsidiaries (the “Partnership”) as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2012 of the Partnership and our report dated February 28, 2013 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 28, 2013

 

64


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except for per unit data)

 

     Year Ended December 31,  
     2012     2011     2010  

Operating revenues

      

Gathering revenue - related party

   $ 88,091      $ 102,427      $ 77,645   

Gathering revenue

     49,420        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

     213,961        205,820        113,590   
  

 

 

   

 

 

   

 

 

 

Operating expenses

      

Product purchases

     23,853        38,787        —     

Product purchases - related party

     15,152        —          —     

Operations and maintenance

     40,617        36,303        25,702   

General and administrative

     25,890        24,153        17,657   

Depreciation, amortization and accretion

     45,726        33,812        22,359   
  

 

 

   

 

 

   

 

 

 

Total operating expenses

     151,238        133,055        65,718   
  

 

 

   

 

 

   

 

 

 

Gain from exchange of property, plant and equipment

     —          1,106        —     
  

 

 

   

 

 

   

 

 

 

Operating income

     62,723        73,871        47,872   

Earnings from unconsolidated affiliate

     3,847        —          —     

Interest and debt expense

     (33,618     (27,617     (13,550
  

 

 

   

 

 

   

 

 

 

Income before income taxes

     32,952        46,254        34,322   

Income tax expense (benefit)

     1,206        1,251        (550
  

 

 

   

 

 

   

 

 

 

Net income

   $ 31,746      $ 45,003      $ 34,872   
  

 

 

   

 

 

   

 

 

 

General partner’s interest in net income

   $ 15,075      $ 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   

 

See accompanying notes.

 

65


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

 

     December 31,  
     2012      2011  
ASSETS      

Current assets

     

Cash and cash equivalents

   $ 21       $ 797   

Accounts receivable - related party

     23,863         27,312   

Accounts receivable

     15,123         11,926   

Insurance receivable

     2,920         —     

Prepaid expenses and other assets

     1,941         1,935   
  

 

 

    

 

 

 

Total current assets

     43,868         41,970   

Investment in unconsolidated affiliate

     128,646         —     

Property, plant and equipment, net of accumulated depreciation of $126,524 in 2012 and $89,860 in 2011

     784,371         746,045   

Intangible assets, net of accumulated amortization of $10,138 in 2012 and $2,440 in 2011

     163,021         127,760   

Goodwill

     95,031         93,628   

Deferred financing costs, net

     17,149         16,699   

Other assets

     1,321         790   
  

 

 

    

 

 

 

Total assets

   $ 1,233,407       $ 1,026,892   
  

 

 

    

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL      

Current liabilities

     

Accrued additions to property, plant and equipment

   $ 3,829       $ 7,500   

Capital leases

     3,862         2,693   

Accounts payable - related party

     3,088         1,308   

Accounts payable, accrued expenses and other liabilities

     27,423         31,794   
  

 

 

    

 

 

 

Total current liabilities

     38,202         43,295   

Long-term debt

     558,161         512,500   

Long-term capital leases

     3,161         3,929   

Asset retirement obligations

     13,188         11,545   

Commitments and contingent liabilities (Note 11)

     

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)

     18,439         11,292   
  

 

 

    

 

 

 

Total partners’ capital

     620,695         455,623   
  

 

 

    

 

 

 

Total liabilities and partners’ capital

   $ 1,233,407       $ 1,026,892   
  

 

 

    

 

 

 

See accompanying notes.

 

66


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

 

     Year Ended December 31,  
     2012     2011     2010  

Cash flows from operating activities

      

Net income

   $ 31,746      $ 45,003      $ 34,872   

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation, amortization and accretion

     45,726        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

     4,284        3,473        4,961   

Changes in assets and liabilities:

      

Accounts receivable - related party

     3,449        (4,309     (23,003

Accounts receivable

     (3,197     (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

     2,740        18,600        603   
  

 

 

   

 

 

   

 

 

 

Net cash provided by operating activities

     89,267        86,331        48,003   
  

 

 

   

 

 

   

 

 

 

Cash flows from investing activities

      

Acquisitions, net of cash acquired

     (87,247     (414,073     —     

Capital expenditures

     (35,493     (48,405     (69,069

Proceeds from exchange of property, plant and equipment

     —          5,943        —     

Investment in unconsolidated affiliate

     (131,250     —          —     

Capital distributions from unconsolidated affiliate

     2,604        —          —     

Proceeds from sale of property, plant and equipment

     20        —          —     

Distributions to Quicksilver for Alliance assets

     —          —          (80,276
  

 

 

   

 

 

   

 

 

 

Net cash used in investing activities

     (251,366     (456,535     (149,345
  

 

 

   

 

 

   

 

 

 

Cash flows from financing activities

      

Proceeds from issuance of senior notes

     151,500        200,000        —     

Proceeds from credit facility

     411,700        215,200        426,704   

Repayments of credit facility

     (517,500     (186,204     (268,600

Payment of Tristate Acquisition deferred payment

     (7,839     —          —     

Payments on capital leases

     (2,993     (1,966     —     

Deferred financing costs paid

     (4,994     (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

     5,930        8,741        —     

Distributions to partners

     (91,558     (64,011     (49,699

Taxes paid for equity-based compensation vesting

     (406     —          (5,293
  

 

 

   

 

 

   

 

 

 

Net cash provided by financing activities

     161,323        370,999        100,598   
  

 

 

   

 

 

   

 

 

 

Change in cash and cash equivalents

     (776     795        (744

Cash and cash equivalents at beginning of period

     797        2        746   
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 21      $ 797      $ 2   
  

 

 

   

 

 

   

 

 

 

Supplemental cash flow information:

      

Interest paid, net of amounts capitalized

   $ 26,948      $ 20,281      $ 8,590   

See accompanying notes.

 

67


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

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

     —          —          —           5,930        5,930   

Net income

     14,149          2,522         15,075        31,746   

Equity-based compensation

     1,877        —          —           —          1,877   

Taxes paid for equity-based compensation vesting

     (406     —          —           —          (406

Distributions to partners

     (77,700     —          —           (13,858     (91,558
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

Partners’ capital as of December 31, 2012

   $ 442,348      $ —        $ 159,908       $ 18,439      $ 620,695   
  

 

 

   

 

 

   

 

 

    

 

 

   

 

 

 

 

See accompanying notes.

 

68


Table of Contents

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO 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.

 

69


Table of Contents

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 5. Net Income Per Limited Partner Unit for additional information concerning ownership interests.

Description of Business

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.

 

70


Table of Contents

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 acquired by Crestwood Marcellus Midstream LLC (CMM, our unconsolidated affiliate), 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.

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 other customers. 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.

 

71


Table of Contents

Investment in Unconsolidated Affiliate

We apply the equity method of accounting where we can exert significant influence over, but do not control or direct, the policies, decisions or activities of the entity. We use the cost method of accounting where we are unable to exert significant influence over the entity. The Financial Accounting Standards Board’s accounting standards related to equity method investments and joint ventures require entities to periodically review their equity method investments to determine whether current events or circumstances indicate that the carrying value of the equity method investment may be impaired. We evaluate our equity investment for impairment when there are indicators of impairment. If indicators suggest impairment we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value of our equity method investment has declined and if any such decline is other than temporary. If a decline in fair value is determined to be other than temporary, the investment’s carrying value is written down to fair value.

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 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.

 

72


Table of Contents

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.

 

73


Table of Contents

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.

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.

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 Acquisition

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   
  

 

 

 

 

74


Table of Contents

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.

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 6. Financial Instruments and Note 15. 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.

 

75


Table of Contents

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.

 

76


Table of Contents

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.

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   

 

77


Table of Contents
      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. INVESTMENT IN UNCONSOLIDATED AFFILIATE

On March 26, 2012, we invested approximately $131 million in cash in exchange for a 35% interest in CMM, which is held by our wholly-owned subsidiary. Crestwood Holdings owns the remaining 65% interest in CMM. We account for our investment in CMM under the equity method of accounting. In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $258 million, which was funded through $129 million of borrowings under our 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, CMM became our wholly-owned consolidated subsidiary.

 

78


Table of Contents

Our investment in CMM totaled approximately $129 million as of December 31, 2012, which equals our respective share of CMM’s equity. The summarized financial information of the operating results and financial position of CMM is as follows (In thousands):

 

     Year Ended
December 31, 2012
 

Operating results data:

  

Operating revenue

   $ 25,502   

Operations and maintenance expense

     2,491   

General and administrative expense

     3,692   

Depreciation and amortization expense

     6,182   

Interest and debt expense

     2,147   
  

 

 

 

Net income

   $ 10,990   

Ownership percentage

     35
  

 

 

 

Equity earnings from CMM

   $ 3,847   
  

 

 

 

Financial position data:

  

Current assets

   $ 6,603   

Non-current assets

     499,213   

Current liabilities

     10,420   

Long-term debt

     127,000   

Members' equity

     367,560   

Distributions:

  

Earnings distributions

   $ 3,847   

Capital distributions

     2,604   
  

 

 

 

Total distributions to CMLP

   $ 6,451   
  

 

 

 

CMM Acquisitions

Antero Resources Appalachian Corporation (Antero) Acquisition. On March 26, 2012, CMM acquired certain of Antero’s gathering system assets located in Harrison and Doddridge Counties, West Virginia for approximately $380 million.

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.

Additionally, CMM entered into a 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero, which provided for an area of dedication of approximately 127,000 gross acres, or 104,000 net acres at the time of acquisition, 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 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, CMM 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.

E Marcellus Asset Company, LLC (EMAC) Acquisition. On December 28, 2012, CMM acquired all of the membership interest in EMAC from Enerven Compression, LLC 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. The assets will

 

79


Table of Contents

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.

Operating Agreement

Concurrent with the formation of CMM, we entered into an operating agreement with CMM to operate its assets. The terms of the operating agreement provide for, among other things, the reimbursement of costs incurred by us on behalf of CMM in conjunction with operating CMM’s assets. For the year ended December 31, 2012, CMM reimbursed us approximately $3 million for costs under the operating agreement which is reflected as a reduction to operating expenses in our consolidated statement of income.

 

5. 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

   $ 31,746      $ 45,003      $ 34,872   

GP’s incentive distributions

     (14,753     (7,049     (2,016
  

 

 

   

 

 

   

 

 

 

Net income after incentive distributions

     16,993        37,954        32,856   

GP’s interest in net income after incentive distributions

     322        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.

 

80


Table of Contents

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