10-K 1 d270993d10k.htm FORM 10-K Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2011

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: 001-32329

 

 

COPANO ENERGY, L.L.C.

(Exact name of registrant as specified in its charter)

 

Delaware   51-0411678
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification No.)
2727 Allen Parkway, Suite 1200
Houston, Texas 77019
  (713) 621-9547
(Address of principal executive offices)   (Registrant’s telephone number, including area code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

 

Title of Each Class

 

Name of Exchange on which Registered

Common Units Representing Limited

Liability Company Interests

  The NASDAQ Global Select Market

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  þ    No  ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  þ

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of 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.  þ

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   þ    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a 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  þ

As of June 30, 2011, the aggregate market value of our voting and non-voting common equity held by non-affiliates of the registrant was approximately $2.2 billion based on $34.22 per common unit, the closing price of our common units as reported on The NASDAQ Global Select Market.

As of February 17, 2012, 72,171,817 of our common units were outstanding.

 

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

Document

  

Parts Into Which Incorporated

Portions of the Proxy Statement for the Annual Meeting of Unitholders of Copano Energy, L.L.C. to be held May 17, 2012    Part III

 

 

 


Table of Contents

TABLE OF CONTENTS

 

         Page  
  PART I   

Item 1.

 

Business

     1   

Item 1A.

 

Risk Factors

     34   

Item 1B.

 

Unresolved Staff Comments

     53   

Item 2.

 

Properties

     53   

Item 3.

 

Legal Proceedings

     54   

Item 4.

 

Mine Safety Disclosures

     54   
  PART II   

Item 5.

 

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

     55   

Item 6.

 

Selected Financial Data

     57   

Item 7.

 

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

     59   

Item 7A.

 

Quantitative and Qualitative Disclosures about Market Risk

     88   

Item 8.

 

Financial Statements and Supplementary Data

     95   

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     95   

Item 9A.

 

Controls and Procedures

     95   

Item 9B.

 

Other Information

     99   
  PART III   

Item 10.

 

Directors, Executive Officers and Corporate Governance

     99   

Item 11.

 

Executive Compensation

     99   

Item 12.

 

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

     99   

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

     99   

Item 14.

 

Principal Accounting Fees and Services

     99   
  PART IV   

Item 15.

 

Exhibits, Financial Statement Schedules

     100   
  FINANCIAL STATEMENTS   

Copano Energy, L.L.C. Index to Financial Statements

     F-1   


Table of Contents

PART I

Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C., its subsidiaries and entities it manages or operates.

As used generally in the energy industry and in this report, the following terms have the meanings indicated below. Please read the subsection of Item 1 captioned “—Industry Overview” for a discussion of the midstream natural gas industry.

 

/d:    Per day
$/gal:    U.S. dollars per gallon
Bbls:    Barrels
Bcf:    One billion cubic feet
Btu:    One British thermal unit
GPM:    Gallons per minute
Lean gas:    Natural gas that is low in NGL content
MMBtu:    One million British thermal units
Mcf:    One thousand cubic feet
MMcf:    One million cubic feet
NGLs:    Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
Residue gas:    The pipeline quality natural gas remaining after natural gas is processed
Rich gas:    Natural gas that is high in NGL content
Tcf:    One trillion cubic feet
Throughput:    The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility

 

Item 1. Business

The following discussion of our business segments provides information regarding our principal processing plants, pipelines and other assets. For a discussion of our results of operations, please read Item 7 of this report, captioned “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

General

We are an energy company engaged in the business of providing midstream services to natural gas producers, including gathering, transportation and processing of natural gas, fractionation and transportation of NGLs and other related services. Our assets are located in Texas, Oklahoma, Wyoming and Louisiana and include approximately 6,800 miles of active natural gas gathering and transmission pipelines and ten natural gas processing plants with over one Bcf/d of combined processing capacity. In addition to our natural gas pipelines, we operate 380 miles of NGL pipelines.

We were formed in August 2001 as a Delaware limited liability company to acquire entities operating under the Copano name since 1992, and to serve as a holding company for our operating subsidiaries. Since our inception in 1992, we have grown through strategic and bolt-on acquisitions and organic growth projects. Our common units are listed on the NASDAQ Global Select Market (NASDAQ”) under the symbol “CPNO.”

Recent Developments

Update on Eagle Ford Shale projects.

 

   

DK pipeline expansion placed in service. In December 2011, we placed into service 59 miles of newly constructed pipeline and related compression through Lavaca and Colorado Counties, Texas that directly connect our existing 38-mile DK pipeline in DeWitt and Karnes Counties, Texas to our

 

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Houston Central complex. The additional compression increased the DK pipeline’s capacity from 225,000 MMBtu per day to 350,000 MMBtu per day. The DK pipeline is supported by firm producer volume commitments and dedicated acreage. This pipeline will provide direct access to the Houston Central complex for volumes from the southwest extension described above.

 

   

DK pipeline southwest extension. On February 9, 2012, we announced plans to extend our DK pipeline approximately 65 miles southwest from DeWitt County into McMullen County, Texas, along the same path as our joint venture condensate pipeline, discussed below, in the rich gas window of the Eagle Ford Shale. The southwest extension is expected to begin service in the first half of 2013 and is projected to cost approximately $120 million. The project is supported by a new long-term, fee-based capacity commitment with a leading operator in the Eagle Ford Shale play. Under the agreement, we will provide gathering, processing and NGL handling services for natural gas from leases in McMullen County, Texas.

 

   

Houston Central complex cryogenic processing upgrade. We have encountered a delay in completing an upgrade to the cryogenic processing facility at our Houston Central complex. Although we previously had anticipated that the full-quarter impact of the Eagle Ford Shale projects we completed in the fourth quarter would be fully reflected in our first-quarter 2012 operating results, we now expect that the effects of downtime at our Houston Central complex and continued delay in completing the cryogenic upgrade will negatively impact our first-quarter Texas segment gross margin.

 

   

Double Eagle Pipeline. Effective December 15, 2011, we entered into agreements to form Double Eagle Pipeline LLC (“Double Eagle Pipeline”), a 50/50 joint venture with Magellan Midstream Partners, L.P. (“Magellan”) to provide condensate gathering and transportation services to Eagle Ford Shale producers. The joint venture intends to construct a pipeline system extending from Gardendale, Texas, in LaSalle County to Three Rivers, Texas, in Live Oak County, then extending north into DeWitt County, Texas. We are converting to condensate service our existing natural gas pipeline that extends from near Three Rivers, Texas to Nueces Bay, Texas, near Corpus Christi and will lease that capacity to the joint venture. Magellan will make available to the joint venture existing and expanded storage assets, and will provide the joint venture’s customers access to marine vessel loading facilities at the Port of Corpus Christi. The pipeline from Three Rivers to Corpus Christi is expected to begin service as early as the fourth quarter of 2012, while the remaining joint venture assets are expected to begin service in the second quarter of 2013. Our 50% share of estimated construction costs associated with the joint venture and our costs to convert our existing pipeline are expected to total approximately $110 million. The joint venture project is supported by long-term fee-based customer commitments from two major producers with significant acreage in the rich gas window of the Eagle Ford Shale.

 

   

Eagle Ford Gathering pipeline placed in full service. Eagle Ford Gathering LLC (“Eagle Ford Gathering”), our joint venture with Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”), began limited service on its Eagle Ford Shale gathering system in August 2011 and on its crossover pipeline in October 2011. Eagle Ford Gathering then began full service on December 1, 2011. The joint venture has secured fee-based contracts with several producers, for combined volume commitments of 637,500 MMBtu per day.

2012 expansion capital. Our estimated 2012 expansion capital expenditures for board-approved projects total approximately $410 million, which includes expenditures for the southwest extension of our DK pipeline, our joint venture with Magellan, our Houston Central processing expansion, additional gathering infrastructure in the Eagle Ford Shale and expansion of our Osage System footprint in Oklahoma to accommodate drilling activity in the Mississippi Lime area.

Recent financings.

 

   

Public debt offering. On February 7, 2012, we completed a registered underwritten offering of an additional $150,000,000 aggregate principal amount of 7.125% senior notes due 2021 (the “new notes”) at 102.25% of their principal amount for net proceeds of approximately $150.1 million,

 

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excluding accrued interest on the new notes and after deducting fees and expenses payable by us (including underwriting discounts and commissions). The new notes are an additional issue of our outstanding 7.125% senior notes due 2021 issued in an aggregate principal amount of $360,000,000 on April 5, 2011. The new notes were issued under the same indenture as the outstanding senior notes due 2021 and are part of the same series of debt securities. We used the net proceeds from the offering of the new notes to repay a portion of the outstanding indebtedness under our revolving credit facility.

 

   

Public equity offering. On January 19, 2012, we completed a registered underwritten offering of 5,750,000 common units at $34.03 per unit, for net proceeds of approximately $187.5 million, after deducting underwriting discounts and offering expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under our revolving credit facility.

Declaration of distribution. On January 11, 2012, our Board of Directors declared a cash distribution for the three months ended December 31, 2011 of $0.575 per common unit. The distribution, totaling $42.1 million, was paid on February 9, 2012 to all common unitholders of record at the close of business on January 26, 2012.

Business Strategy

Our management team is committed to our mission of building a more diversified energy midstream company with scale, stability of cash flows, above-average returns on invested capital and providing secure and growing distributions to our unitholders. Key elements of our strategy include:

 

   

Executing on organic growth opportunities and bolt-on acquisitions. We pursue capital projects and complementary acquisitions that we believe will enhance our ability to increase cash flows from our existing assets by capitalizing on our existing infrastructure, personnel and customer relationships. For example, we have completed significant expansions of our Texas assets to capitalize on significant activity in the Eagle Ford Shale and the north Barnett Shale Combo, and we are capitalizing on our existing assets in connection with a new condensate joint venture to meet continued demand from Eagle Ford Shale producers. In addition, we increased our processing capacity and operating flexibility and improved our margins in Oklahoma by acquiring the Harrah processing plant. Where our pipelines and processing or fractionation facilities have excess capacity, we have opportunities to increase throughput volume and cash flow with minimal incremental costs. We seek to increase volumes and utilization of capacity by aggressively marketing our services to producers to connect new supplies of natural gas.

 

   

Reducing sensitivity to commodity prices. The volatility of natural gas and NGL prices is a key consideration as we enter into new contracts and review opportunities for growth. Our goal is to position ourselves to achieve stable cash flows in a variety of market conditions. Generally, we pursue contracts under which the compensation for our services is not directly dependent on commodity prices. For example, we have focused on replacing commodity-sensitive contracts with fee-based contracts in executing our strategy to increase volumes from the Eagle Ford Shale, the north Barnett Shale Combo play and the Woodford Shale. In addition, we pursue opportunities to increase the fee-based component of our contract portfolio through acquisitions or other growth projects. To the extent that our contracts are commodity sensitive, we use derivative instruments to hedge our exposure to commodity price risk. We have established a product-specific, option-focused portfolio designed to allow us to meet our debt service, maintenance capital expenditure and similar requirements, along with our distribution objectives, despite fluctuations in commodity prices. Please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

 

   

Expanding through greenfield opportunities and strategic acquisitions. We pursue significant greenfield projects that leverage our strengths through alignment with producers and downstream customers. We also pursue potential acquisitions in new regions that we believe will enhance the scale and diversity of our assets or otherwise offer cash flow and operational growth opportunities that are attractive to us.

 

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Pursuing profitable growth. We believe that a disciplined approach in selecting new projects will better enable us to choose opportunities that deliver value for our company and our unitholders. In analyzing a particular acquisition, expansion or greenfield project, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets or projects, strategic fit in relation to our existing business, expertise and management personnel required, capital required to integrate and maintain the assets involved, and the surrounding competitive environment. From a financial perspective, we analyze the rate of return the assets are expected to generate relative to our cost of capital under various volume and commodity price scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.

 

   

Developing and exploiting flexibility in our operations. Flexibility is a fundamental consideration underlying our approach to developing, expanding or acquiring assets. We can modify the operation of our assets to maximize our cash flows. For example, we can operate several of our processing plants in ethane-rejection mode as commodity price environments or operating conditions warrant. In 2010 and 2011, we focused on developing our ability to offer Eagle Ford Shale producers access to multiple natural gas and NGL markets. Multiple residue markets are available at the tailgate of our Houston Central complex, and in 2010 and 2011, we secured alternatives for NGL handling through initiatives such as the start-up and expansion of our Houston Central fractionator, our Liberty pipeline project and our execution of third-party fractionation or purchase arrangements for NGLs or purity products, including agreements with petrochemical customers along the Texas Gulf Coast.

 

   

Maintaining a strong balance sheet and access to liquidity. We are committed to pursuing growth in a way that allows us to maintain the strength of our balance sheet and a liquidity position that allows us to execute our business strategy in various commodity price environments. For example, we financed a substantial portion of our initial Eagle Ford Shale capital expenditures though a private placement of preferred equity with an affiliate of TPG Capital, L.P., which included a paid-in-kind distribution feature that allowed us the flexibility to maintain a strong balance sheet and liquidity position during construction and expansion of our assets and prior to generating cash flow from these projects. Other recent transactions through which we increased our liquidity include amendment and restatement of our senior secured revolving credit facility in June 2011, a public equity offering in January 2012, and a public debt offering in February 2012.

 

   

Maintaining an approach to business founded on a culture of integrity, safety, service and creativity. We believe that the dedication of our employees is a critical component of our success. We seek to maintain a company culture that fosters integrity, is committed to safety and environmental compliance and encourages innovation and teamwork, which we believe will allow us to attract and retain high quality employees and deliver the superior service required to establish and maintain valued long-term commercial relationships.

Our Operations

Through our subsidiaries and equity investments, we own and operate natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. Our natural gas pipelines gather natural gas from wellheads or designated points near producing wells. We treat and process natural gas as needed to remove contaminants and extract mixed NGLs and deliver the resulting residue gas to third-party pipelines, local distribution companies, power generation facilities and industrial customers. We sell extracted NGLs as a mixture or as fractionated purity products and deliver them through our pipeline interconnects and truck loading facilities. We process natural gas from our own gathering systems and from third-party pipelines, and in some cases we deliver natural gas and mixed NGLs to other third parties who provide us with transportation, processing or fractionation services. In addition, as described above under “Recent Developments—Double Eagle Pipeline,” we expect to begin providing condensate services to Eagle Ford Shale producers in late 2012.

 

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Our Operating Segments

Overview

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Texas, Oklahoma and Rocky Mountains.

Operating Segments

 

                        Year Ended
December 31, 2011
 

Segment

  

Assets

   Pipeline Miles(1) /
Number of
Processing Plants
     Throughput/
Inlet

Capacity(2)(3)
     Average
Throughput/
Inlet
Volumes(2)(3)
     Utilization of
Capacity
 

Texas

   Natural Gas Pipelines(4)      2,210         1,945,000         538,457         28
   Processing Plants(5)      3         1,000,000         597,888         60
   NGL Pipelines(6)      377         165,250         27,039         20

Oklahoma

   Natural Gas Pipelines      3,967         382,100         252,583         66
   Processing Plants(7)      7         224,000         119,914         54

Rocky Mountains

   Natural Gas Pipelines(8)      597         1,550,000         632,196         41

 

(1) Natural gas pipeline miles for Texas and Oklahoma exclude 522 miles and 2,960 miles, respectively, of inactive pipelines that are being held for potential future development.
(2) Capacity and volumes presented include wholly owned assets and assets owned by unconsolidated affiliates in which we own interests. Capacity values generally are based on current operating configurations and could be increased or decreased through addition or removal of compression, delivery meter capacity or other facility modifications.
(3) Natural gas capacity and volumes are presented in Mcf/d. NGL capacity and volumes are presented in Bbls/d.
(4) Includes a 153-mile gathering system owned by Webb/Duval Gatherers, an unconsolidated general partnership in which we own a 62.5% interest, and a 188-mile gathering system owned by Eagle Ford Gathering, an unconsolidated company in which we own a 50% interest.
(5) Includes our processing plant in Lake Charles, Louisiana, which was restarted in November 2011.
(6) Includes an 87-mile NGL pipeline owned by Liberty Pipeline Group LLC, an unconsolidated affiliate in which we own a 50% interest, and 127 miles of leased NGL pipelines.
(7) Includes a processing plant owned by Southern Dome, LLC, an unconsolidated affiliate in which we own a majority interest.
(8) Owned by Bighorn Gas Gathering, L.L.C. and Fort Union Gas Gathering, L.L.C., unconsolidated affiliates in which we own 51% and 37.04% interests, respectively.

For additional disclosure about our segments, please read Note 14, “Segment Information,” to our consolidated financial statements included in Item 8 of this report.

Texas

Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation services. This segment includes a processing plant located in southwest Louisiana and:

 

   

our 62.5% interest in Webb Duval Gatherers (“Webb Duval”), which provides natural gas gathering in south Texas;

 

   

our 50% interest in Eagle Ford Gathering, which provides midstream natural gas services to Eagle Ford Shale producers;

 

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our 50% interest in Liberty Pipeline Group LLC (“Liberty Pipeline Group”), which transports mixed NGLs from our Houston Central complex to the Texas Gulf Coast; and

 

   

our 50% interest in Double Eagle Pipeline, which is constructing a condensate gathering system that will serve Eagle Ford Shale producers.

 

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The following map represents our Texas segment:

 

LOGO

 

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The tables below provide summary descriptions of our Texas pipeline systems and processing plants.

Texas Pipelines

 

                         Year Ended
December 31, 2011
 
     Length      Diameter
Pipe
     Throughput
Capacity(1)(2)
    Average
Throughput(2)(3)
     Utilization of
Capacity
 
     (miles)      (range)                      

Wholly Owned

             

Natural Gas Pipelines:

             

South Texas

     948         2”-20”         721,000        186,561         30

Houston Central

     332         2”-12”         239,000        88,917         37

Upper Gulf Coast

     233         2”-12”         145,000        49,220         34

Saint Jo(4)

     356         3”-16”         122,000        75,585         62

Third Party(5)

           125,000        163,425         131

NGL Pipelines:

             

Houston Central NGL Lines(6)

     285         4”-8”         72,250        15,566         22

Saint Jo NGL Lines

     5         6”         18,000        6,876         38

Joint Ventures

             

Natural Gas Pipelines:

             

Eagle Ford Gathering(7)

     188         12”-30”         500,000        92,258         18

Webb Duval

     153         4”-16”         218,000        45,916         21

NGL Pipelines:

             

Liberty Pipeline(8)

     87         12”         75,000 (8)      4,597         9

 

(1) Capacity values generally are based on current operating configurations and could be increased or decreased through addition or removal of compression, delivery meter capacity or other facility modifications.
(2) Natural gas capacity and volumes are presented in Mcf/d. NGL capacity and volumes are presented in Bbls/d.
(3) Throughput volumes presented in the table are net of intercompany transactions.
(4) Excludes 522 miles of inactive pipelines held for potential future development.
(5) Reflects capacity under significant third-party arrangements.
(6) Includes 127 miles of leased NGL pipelines. Excludes our capacity on the Liberty pipeline.
(7) Capacity may be increased in 2012 to 585,000 Mcf/d through added compression.
(8) Reflects Liberty pipeline’s total capacity. We have 37,500 Bbls/d of firm capacity on the pipeline.

Texas Processing

 

              Year Ended December 31, 2011  

Processing Plants

 

Facilities

  Throughput
Capacity(1)
    Fractionation
Capacity(1)
    Average
Inlet
Volumes(1)(2)
    Utilization of
Capacity
    Average Processing
Volumes
 
                                   NGLs(1)        Residue(1)  

Wholly Owned

             

Houston Central(3)

  Cryogenic/lean oil     700,000        44,000        518,781        74     20,250        430,077  

Saint Jo

  Cryogenic     100,000        —          68,127        68     6,876        55,867  

Lake Charles

  Cryogenic     200,000        —          10,980 (2)      6     78 (2)      10,846 (2) 

Third Party(4)

      —          5,000-7,000          —          —          —    

Joint Ventures

             

Eagle Ford Gathering

             

Third Party(5)

      100,000        —          103,000        103     6,881        90,661  

 

(1) Natural gas capacity and volumes are presented in Mcf/d. Fractionation capacity and NGL volumes are presented in Bbls/d. Residue volumes are presented in MMBtu/d.

 

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(2) Average inlet volumes and average processing volumes for the Lake Charles plant represent 28 days of activity in 2011. We restarted Lake Charles in November 2011 and operate the plant when it is economic to do so.
(3) We have committed 375,000 MMBtu/d (approximately 312,240 Mcf/d) of firm capacity at Houston Central to Eagle Ford Gathering.
(4) Reflects capacity under third-party arrangement discussed in the narrative description of our Texas segment under “—Liberty Pipeline”. Deliveries averaged 3,184 bbls/d during the 149 days of activity in 2011.
(5) Does not include Eagle Ford Gathering’s 375,000 MMBtu/d (approximately 312,240 Mcf/d) of firm capacity at our Houston Central complex. Eagle Ford Gathering’s third-party processing capacity will increase to 330,000 MMBtu/d (approximately 275,000 Mcf/d) in the second quarter of 2013.

In addition to transporting natural gas to our plants, our Texas segment delivers natural gas to third-party service providers. Depending on our contractual arrangements, third-party processors collect transportation or processing fees, retain a portion of the NGLs or residue gas or retain a portion of the proceeds from the sale of the NGLs and residue gas in exchange for their services. Average daily volumes processed at third-party plants for our Texas segment were 22,600 Mcf/d for the year ended December 31, 2011.

As described above under “—Recent Developments,” we have undertaken various expansion capital projects in Texas to accommodate volume growth from the Eagle Ford Shale play. The table below provides summary descriptions of our major Texas capital projects.

 

Texas Expansion Projects

Project

  Miles     Diameter     Change in
Capacity(1)
    Total
Capacity(1)
    Estimated
Capital
   

Expected
In-Service Date

          (range)     (expansions
only)
          (in millions)      

Ongoing

           

Wholly Owned

           

Houston Central cryogenic upgrade(2)

    —          —          —   (2)      700,000 (2)    $ 21      First Quarter 2012

Houston Central processing expansion

    —          —          400,000        1,100,000      $ 145      First Quarter 2013

Goebel conversion(4)

    46        12”-14”        —          —   (4)    $ 17      Fourth Quarter 2012

DK pipeline southwest extension

    65        24”        —          —   (5)    $ 120      Second Quarter 2013

Joint Ventures

           

Double Eagle Pipeline

    142        12”-16”        —          100,000 (4)    $ 150      First Quarter 2013

Completed

           

Wholly Owned

           

Houston Central fractionation expansion

    —          —          22,000        44,000      $ 42      In service

DK pipeline extension

    59        24”        195,000        350,000      $ 148      In service

Joint Ventures

           

Eagle Ford Gathering

           

Initial pipeline

    117        12”-30”        —          500,000      $ 152 (7)    In service

Crossover pipeline(6)

    71        20”-24”        —          375,000      $ 127 (7)    In service

Liberty NGL pipeline

    87        12”        —          75,000      $ 60 (7)    In service

 

(1) Natural gas capacity and volumes are presented in Mcf/d. NGL and condensate capacity and volumes are presented in Bbls/d.
(2) Consists of upgrading our existing processing facility with a more efficient cryogenic tower to allow for processing of very rich natural gas from the Eagle Ford Shale.
(3) We are converting our Goebel pipeline from natural gas to condensate service and will lease the pipeline to Double Eagle Pipeline for condensate transportation service.

 

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(4) The Double Eagle Pipeline system and the Goebel pipeline together will provide 100,000 Bbl/d of condensate transportation capacity from the Eagle Ford Shale to the Texas Gulf Coast.
(5) The DK pipeline with the southwest extension will have 350,000 Mcf/d of capacity.
(6) Includes lateral pipelines and equipment for interconnections between the crossover pipeline and Williams Partners, LP’s and Formosa Hydrocarbons Company’s processing plants.
(7) Joint venture project costs presented are gross amounts; our share of such costs is 50%.

 

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The following map summarizes our Texas expansion projects:

 

LOGO

 

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South Texas Systems

We deliver a substantial majority of the natural gas gathered on our wholly owned gathering systems in south Texas to our Houston Central complex, where we provide treating, processing and NGL fractionation and transportation services, as needed. Our gathering systems in this area have access to Houston Central directly, through our own DK pipeline and through the Laredo-to-Katy pipeline, a 30-inch natural gas transmission pipeline owned by a subsidiary of Kinder Morgan, which extends along the Texas Gulf Coast from south Texas to Houston. Our Houston Central complex straddles the Laredo-to-Katy pipeline, which has allowed us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central complex and downstream markets.

We completed the interconnection of our DK pipeline and Houston Central complex in December 2011, which when coupled with Kinder Morgan’s Laredo-to-Katy pipeline, significantly increased pipeline capacity for deliveries to our Houston Central complex. Most of the gas from our wholly owned gathering systems now reaches Houston Central via the DK pipeline, and as described below, deliveries to Houston Central via the Laredo-to-Katy line increasingly consist of natural gas that Kinder Morgan is transporting for Eagle Ford Gathering.

We also deliver gas from our south Texas gathering systems to other third party pipelines and processing plants. Depending on our contractual arrangements, third-party service-providers collect processing fees, retain a portion of the NGLs or residue gas or retain a portion of the proceeds from the sale of the NGLs and residue gas in exchange for their services.

Eagle Ford Gathering. We and Kinder Morgan provide midstream natural gas services to Eagle Ford Shale producers through our 50/50 joint venture, Eagle Ford Gathering. Kinder Morgan has committed to Eagle Ford Gathering 375,000 MMBtu/d of transportation capacity on its Laredo-to-Katy pipeline, and we have committed 375,000 MMBtu/d of processing capacity at our Houston Central complex. Eagle Ford Gathering gathers natural gas from the western Eagle Ford Shale play on its 117-mile, 30-inch and 24-inch natural gas pipeline and delivers the gas to Kinder Morgan’s Laredo-to-Katy pipeline at an interconnect in Duval County, Texas. Kinder Morgan then transports the gas either to our Houston Central complex for processing or to Eagle Ford Gathering’s crossover pipeline system, a 70-mile, 20- and 24-inch pipeline system through which Eagle Ford Gathering delivers gas to the Williams Markham plant for processing. Eagle Ford Gathering will also deliver gas to Formosa Hydrocarbons Company, Inc. (“Formosa”), via the crossover system when Eagle Ford Gathering’s processing capacity at Formosa becomes available in March 2012.

We serve as managing member of Eagle Ford Gathering, and as operator of its main gathering system in the Eagle Ford Shale. Kinder Morgan serves as operator of Eagle Ford Gathering’s crossover pipeline system.

Webb/Duval Gatherers. Our south Texas systems include the Webb Duval gathering system, which is owned by Webb/Duval Gatherers, a general partnership that we operate and in which we own a 62.5% interest. Each partner has the right to use its pro rata share of pipeline capacity on this system, subject to applicable ratable take and common purchaser statutes.

Houston Central Complex. Our Houston Central complex has approximately 700,000 Mcf/d of processing capacity and includes a 1,100 GPM amine treating system, a 44,000 Bbls/d NGL fractionation facility, a truck rack to facilitate the transport of NGLs and 882,000 gallons of NGL storage capacity.

We are expanding the plant’s cryogenic processing capacity by 400,000 Mcf/d and expect to place the additional capacity in service in the first quarter of 2013.

Houston Central takes deliveries of natural gas from our recently completed DK pipeline, our Houston Central gathering systems and the Kinder Morgan Laredo-to-Katy pipeline. The plant has tailgate interconnects with Kinder Morgan, Houston Pipe Line, Tennessee Gas Pipeline Company and Texas Eastern Transmission for

 

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redelivery of residue natural gas. In addition, we operate NGL pipelines at the tailgate of the plant, and Enterprise Product Partners operates a crude oil and stabilized condensate pipeline that runs from the tailgate of the plant to refineries in the greater Houston area.

The plant and related facilities are located on a 163-acre tract of land, which we lease under three long-term lease agreements.

NGL Pipelines. Our NGL pipelines transport purity ethane and propane from the fractionator at our Houston Central complex to Dow Hydrocarbons. In addition, we have the option to deliver NGLs into Enterprise Products Partners’ Seminole Pipeline. We also transport butylenes for a third party from Almeda in south Houston to the Shell Deer Park plant on the Houston Ship Channel.

We lease two of our NGL pipelines from Dow Hydrocarbons and another from Kinder Morgan under long-term lease agreements.

Liberty Pipeline. The Liberty pipeline (owned through our 50/50 joint venture with Energy Transfer Partners) extends approximately 87 miles, from our Houston Central complex in Colorado County, Texas, first to an NGL product storage facility in Matagorda County, Texas, and then to Formosa’s processing and fractionation facility. We have a minimum of 37,500 Bbls/d of firm capacity on the Liberty pipeline, which enables us to transport mixed NGLs for delivery to Formosa. We have a long-term fractionation and product purchase agreement with Formosa, which initially provides us access to 5,000 to 7,000 BBls/d of fractionation and NGL product sales, and will provide us with up to 37,500 Bbls/d of fractionation and product sales beginning in early 2013, after Formosa completes an expansion of its facilities.

Double Eagle Pipeline. We and Magellan formed Double Eagle Pipeline to provide condensate services for Eagle Ford Shale producers. The 50/50 joint venture will construct and own a condensate gathering and transportation system extending from Gardendale, Texas, in LaSalle County to Three Rivers, Texas, in Live Oak County, then extending north into central DeWitt County. We are converting the Goebel pipeline, one of our existing natural gas pipelines, which extends from near Three Rivers to near Corpus Christi, to condensate service and will lease that capacity to the joint venture. The initial capacity of the 182-mile pipeline system will be 100,000 Bbls/d. Double Eagle will also construct a truck unloading and 400,000 Bbls storage facility along the pipeline near Three Rivers for deliveries of condensate destined for Corpus Christi. Magellan will make enhancements to its Corpus Christi terminal, including the construction of 500,000 Bbls of new condensate storage, which it will make available to the joint venture, and a new dock delivery pipeline for use by the joint venture’s producer-customers. The project is supported by long-term customer commitments from Talisman Energy USA Inc. and Statoil Marketing and Trading (US) Inc. The pipeline from Three Rivers to Corpus Christi is expected to begin service as early as the fourth quarter of 2012, while the remaining joint venture assets are expected to begin service in the second quarter of 2013. We will serve as operator of Double Eagle Pipeline.

Upper Gulf Coast Systems

Our Upper Gulf Coast systems gather lean natural gas from counties to the north of Houston, Texas and take deliveries from several third-party pipelines. We deliver the natural gas gathered or transported on these systems for sale to utilities and industrial customers.

Saint Jo Systems

Our pipelines in north Texas gather natural gas from the north Barnett Shale Combo play in Cooke, Denton, Montague and Wise Counties and deliver the gas to our Saint Jo processing plant in Montague County and to third-party processing plants and pipelines. Our systems in north Texas have interconnects with Targa Resources, Atlas Pipeline, SemGas, Atmos and Natural Gas Pipeline of America. We constructed our Saint Jo plant and placed it in service in September 2009, then expanded the plant’s capacity from 50,000 Mcf/d to 100,000 Mcf/d

 

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in November 2010. The Saint Jo plant includes a 1,100 GPM amine treating facility and condensate stabilization facilities and also has the capability of reduced recovery. We are expanding Saint Jo’s amine treating capacity by 400 GPM and expect to place the additional capacity into service in March 2012. Our Saint Jo NGL pipeline transports NGLs from the plant to ONEOK Hydrocarbon’s Arbuckle NGL pipeline.

Oklahoma

Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including primarily low-pressure gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our majority interest in Southern Dome, LLC (“Southern Dome”), which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County.

 

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The following map represents our Oklahoma segment:

 

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The tables below provide summary descriptions of our Oklahoma pipeline systems and processing plants.

Oklahoma Pipelines

 

                       Year Ended
December 31, 2011
 

Natural Gas Pipelines

   Length
(miles)
   

Diameter of
Pipe

(range)

   Throughput
Capacity(1)(2)
     Average
Throughput(1)(2)
     Utilization
of  Capacity
 

Stroud

     925      2”-16”      113,000         90,898         80.4

Milfay

     367      2”-16”      15,000         8,793         58.6

Glenpool

     1,019      2”-10”      20,000         7,069         35.3

Twin Rivers

     560      2”-12”      23,000         13,386         58.2

Central Oklahoma(3)

     232      2”-10”      4,100         3,742         91.3

Osage

     571      2”-8”      34,000         17,518         51.5

Mountain(4)

     216      2”-20”      135,000         97,299         72.1

Harrah

     77      2”-12”      38,000         13,878         36.5

 

(1) Capacity values generally are based on current operating configurations and could be increased or decreased through addition or removal of compression, delivery meter capacity or other facility modifications.
(2) Natural gas capacity and volumes are presented in Mcf/d.
(3) Excludes 2,960 miles of inactive pipelines held for potential future development.
(4) The Mountain system consists of three separate systems: Blue Mountain, Cyclone Mountain and Pine Mountain.

Oklahoma Processing

 

              Year Ended December 31, 2011  

Processing Plants

 

Facilities

  Throughput
Capacity(1)
    Average
Inlet
Volumes(1)
    Utilization
of Capacity
    Average  Processing
Volumes(1)
 
          NGLs     Residue  

Wholly Owned

           

Paden

  Cryogenic and propane refrigeration Nitrogen rejection(3)     100,000        73,710        73.7     11,938        57,098   

Milfay

  Propane refrigeration     15,000        8,057        53.7     722        7,044   

Glenpool

  Cryogenic     25,000        6,485        25.9     334        5,933   

Burbank

  Propane refrigeration     10,000        6,069        60.7     418        5,135   

Harrah

  Cryogenic     38,000        15,899        41.8     1,833        12,119   

Davenport

  Cryogenic     18,000        —          —          —          —     

Joint Ventures

           

Southern Dome(2)

  Propane refrigeration     18,000        9,694        53.9     397        9,116   

 

(1) Natural gas capacity and volumes are presented in Mcf/d. NGL volumes are presented in Bbls/d. Residue volumes are presented in MMBtu/d.
(2) We own a majority interest in Southern Dome, which owns the Southern Dome plant. The plant is designed for operating capacity of 30,000 Mcf/d. Throughput currently is limited to 18,000 Mcf/d due to inlet compression.
(3) The nitrogen rejection unit removes entrained nitrogen from the natural gas stream associated with the cryogenic portion of the Paden plant, which has capacity of 60,000 Mcf/d.

In addition to gathering natural gas to our plants, our Oklahoma segment delivers natural gas to third-party plants. Depending on our contractual arrangements, third parties collect processing fees, retain a portion of the NGLs or residue gas or retain a portion of the proceeds from the sale of the NGLs and residue gas in exchange for their services. Average daily volumes processed at third-party plants for our Oklahoma segment were 20,703 Mcf/d for the year ended December 31, 2011.

 

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Stroud System and Interconnected Area

The Stroud system is located in Lincoln, Oklahoma, Pottawatomie, Seminole and Okfuskee Counties, Oklahoma. In 2011, we delivered approximately 75% and 13% of the average throughput on this system to our Paden and Harrah plants, respectively, and we delivered the remainder to third-party processing plants.

The Paden plant has a 60,000 Mcf/d turbo-expander cryogenic facility placed in service in June 2001, and a 40,000 Mcf/d refrigeration unit that was added in May 2007. The Paden plant also has the ability to reduce (by approximately 22%) the ethane extracted from natural gas processed, or “ethane rejection” capability. This capability provides us an advantage when market prices or operating conditions make it more desirable to retain ethane within the gas stream. Field compression provides the necessary pressure at the plant inlet, eliminating the need for inlet compression. The plant also has inlet condensate facilities, including vapor recovery and condensate stabilization.

Wellhead production around the Paden plant includes natural gas high in nitrogen, which is inert and reduces the Btu value of residue gas. In 2008, we added a nitrogen rejection unit to the Paden plant, which allows us to process high-nitrogen natural gas while remaining in compliance with downstream pipeline gas quality specifications. The nitrogen rejection unit removes excess nitrogen from residue gas at the tailgate of the plant’s cryogenic facility.

We deliver residue gas from the Paden plant to either Enogex (a subsidiary of OGE Energy Corp.) or ONEOK Gas Transmission. We deliver NGLs from the Paden plant to ONEOK Hydrocarbon and condensate is trucked by Enterprise Product Partners.

On April 1, 2011, we purchased the Harrah processing plant, a 38,000 Mcf/d natural gas processing plant and related gathering facilities in Oklahoma County, Oklahoma, for $16.1 million, funded with cash on hand. Our Oklahoma segment historically delivered natural gas to the Harrah plant for processing. This acquisition enables us to increase our margin on gas processed at the Harrah plant and provides us with additional cryogenic processing capacity and access to Enogex’s intrastate pipeline system for natural gas sales.

Milfay System and Processing Plant. The Milfay system is located in Tulsa, Creek, Lincoln and Okfuskee Counties, Oklahoma. We deliver natural gas gathered on the Milfay system to our Milfay plant, and have the ability to deliver to the Paden plant as well. We deliver the residue gas from the Milfay plant into ONEOK Gas Transmission and the NGLs to ONEOK Hydrocarbon.

Glenpool System and Processing Plant. The Glenpool system is located in Tulsa, Wagoner, Muskogee, McIntosh, Okfuskee, Okmulgee and Creek Counties, Oklahoma. Substantially all of the natural gas from the Glenpool system is delivered to our Glenpool plant. We deliver the residue gas from the Glenpool plant into either ONEOK Gas Transmission or the American Electric Power Riverside power plant, and the NGLs to ONEOK Hydrocarbon.

Twin Rivers System. The Twin Rivers system is located in Okfuskee, Seminole, Hughes, Pontotoc and Coal Counties, Oklahoma. We deliver substantially all of the Twin Rivers system’s volumes to a third-party plant for processing.

Central Oklahoma System. The Central Oklahoma system consists of five gathering systems located in Garvin, Stephens, McClain, Oklahoma and Carter Counties, Oklahoma. We deliver gas gathered on the Central Oklahoma system to two third-party plants for processing.

Osage System. The Osage system is located in Osage, Pawnee, Payne, Washington and Tulsa Counties, Oklahoma. Wellhead production on the eastern portion of the Osage system tends to be lean and is not processed. This gas makes up the majority of the system throughput and is delivered to Enogex and ONEOK Gas Transmission. Wellhead production on the western portion of the Osage system tends to be richer; we currently deliver a portion of the production to Keystone Gas, which delivers it to a third-party processor. We began

 

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directing rich gas from the Osage system to our new Burbank plant in the second quarter of 2010. The Burbank plant, located in Osage County, is a 10,000 Mcf/d natural gas processing plant that we placed in service in the second quarter of 2010. We deliver the residue gas from the Burbank plant into PostRock KPC Pipeline and sell the NGLs to Murphy Energy via trucks.

Mountain Systems. The Mountain systems are located in Atoka, Pittsburg and Latimer Counties, in the Arkoma Basin, and include the Blue Mountain, Cyclone Mountain and Pine Mountain systems. In 2011, we added amine treating and compression services to our Cyclone Mountain system to expand its ability to service development in the Woodford Shale. Wellhead production on the Blue and Pine Mountain systems generally does not require processing or treating. We deliver natural gas from the Mountain systems to, among others, CenterPoint and Enogex.

Southern Dome. We own a majority interest in Southern Dome, which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County. We are the managing member of Southern Dome and serve as its operator. Southern Dome also operates a 3.4-mile gathering system owned by a single producer. Under a gas purchase and processing agreement between Southern Dome and this producer, substantially all of the natural gas from the gathering system is delivered to the Southern Dome processing plant, and the remainder is delivered to a third party for processing. Southern Dome receives a fee for operating the gathering system and retains a percentage of the producer’s residue gas and NGLs at the tailgate of the Southern Dome plant. We deliver the residue gas to ONEOK Gas Transmission and sell the NGLs to Murphy Energy via trucks.

We are obligated to make 73% of capital contributions requested by Southern Dome up to a maximum commitment amount of $18.25 million. We are entitled to receive 69.5% of member distributions until “payout,” which refers to a point at which we have received distributions equal to our capital contributions plus an 11% return. After payout occurs, we will be entitled to 50.1% of member distributions. As of December 31, 2011, we have made $12.4 million in aggregate capital contributions to Southern Dome and have received an aggregate of $14.2 million in member distributions.

Rocky Mountains

Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. This segment includes:

 

   

our 51% interest in Bighorn Gas Gathering, L.L.C. (“Bighorn”), which provides gathering services to Powder River Basin producers; and

 

   

our 37.04% interest in Fort Union Gas Gathering, L.L.C. (“Fort Union”), which provides gathering and treating services to Powder River Basin producers.

Our Rocky Mountains segment also includes firm gathering agreements with Fort Union and firm transportation agreements with Wyoming Interstate Gas Company (“WIC”). We acquired the business and assets in this segment through our purchase of Denver-based Cantera in October 2007.

Rocky Mountains Pipelines and Services(1)

 

                         Year Ended
December 31, 2011
 
     Length
(miles)
     Diameter  of
Pipe

(range)
     Throughput
Capacity(2)
    Average
Throughput(2)
     Utilization
of  Capacity
 

Joint Ventures

             

Natural Gas Pipelines(3)

     597         6”-24”         1,550,000 (4)      632,196         40.8

 

(1) Capacity values generally are based on current operating configurations and could be increased or decreased through addition or removal of compression, delivery meter capacity or other facility modifications.

 

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(2) Natural gas capacity and volumes are presented in Mcf/d.
(3) Consists of pipelines owned by Bighorn and Fort Union. Fort Union also has 1,500 GPM of amine treating capacity.
(4) Includes our capacity under gathering agreements with Fort Union.

 

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The following map represents the assets of Bighorn and Fort Union:

 

LOGO

 

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Bighorn Gathering System

Bighorn provides low and high pressure natural gas gathering service to coal-bed methane producers in the Powder River Basin. Due to the lean nature of coal-bed methane wellhead production, gas gathered on the Bighorn system does not require processing and is delivered directly into the Fort Union gas gathering system at the southern terminus of the Bighorn system. We serve as managing member and field operator of Bighorn.

Fort Union Gathering System

Fort Union takes delivery of gas from Bighorn, provides gathering services to other producers and provides amine treating at its Medicine Bow treating facility in order to meet the quality specifications of downstream pipelines. Pipeline interconnects downstream from the Fort Union system include WIC, Kinder Morgan Interstate Gas Transportation Company and Colorado Interstate Gas Company.

Fort Union has firm gathering agreements with each of its owners, including us. Pursuant to these gathering agreements, each of Fort Union’s owners is obligated to pay for a fixed quantity of firm gathering capacity (referred to as demand capacity) on the system, regardless of the owner’s actual volumes delivered to Fort Union. Also, each owner has the right to use a fixed quantity of firm gathering capacity on the system (referred to as variable capacity) that must be paid for only to the extent the owner’s dedicated production exceeds that owner’s demand capacity. Any capacity not used by the owners becomes available to third parties under interruptible gathering agreements.

The demand capacity arrangement is intended to ensure that Fort Union recovers its costs for capital projects plus a minimum rate of return on its capital invested. As a project’s costs are recovered, the owners’ respective demand capacity related to that project converts to variable capacity. Currently, 48% of Fort Union’s total firm capacity is demand capacity, which expires in 2017. The variable capacity gathering agreements between Fort Union and its owners terminate only upon mutual agreement of the parties. We serve as the managing member of Fort Union. Western Gas Wyoming, L.L.C. (“Western”), a subsidiary of Anadarko, acts as field operator, and a ONEOK Partners subsidiary acts as administrative manager and provides gas control, contract management and contract invoicing services.

Producer Services

We provide services to a number of producers in the Powder River Basin, including producers who deliver gas into the Bighorn or Fort Union gathering systems, using our firm capacity on Fort Union and WIC to provide producers access to downstream interstate markets.

Our gathering agreements with Fort Union currently provide us with total capacity of 397,269 Mcf/d, consisting of demand capacity of 125,000 Mcf/d and variable capacity of up to 272,269 Mcf/d. Under these agreements, Fort Union gathers gas from producers and from Bighorn and delivers it to WIC near Glenrock, Wyoming. Our transportation agreements with WIC provide us with 216,100 MMBtu/d of firm capacity on WIC’s Medicine Bow lateral pipeline. WIC transports natural gas from the terminus of the Fort Union system, as well as other receipt points, to the Cheyenne Hub, which provides a connection to five major interstate pipelines.

Our long-term WIC agreements extend through 2019, with a right to renew for additional five-year terms. Through the capacity release program established under WIC’s Federal Emergency Regulatory Commission (“FERC”) gas tariff, we have released our WIC capacity to several producers in the Powder River Basin. The producers, in turn, have agreed to pay WIC for the right to use our WIC capacity. Our WIC capacity release covers all of our long-term WIC capacity and continues through 2019. We are obligated to pay for our capacity on WIC’s Medicine Bow lateral regardless of whether we use the capacity. Notwithstanding our capacity release, we remain obligated to pay WIC for such capacity in the event and to the extent that a replacement shipper to whom such capacity has been released fails to pay.

 

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Natural Gas Supply

We continually seek new supplies of natural gas, both to increase throughput volume and to offset natural declines in production from connected wells. We obtain new supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage or by obtaining supplies that were previously gathered by competitors. We contract for supplies of natural gas from producers under a variety of contractual arrangements. Please read “—Industry Overview—Midstream Contracts” below and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

We generally do not obtain reservoir engineering reports evaluating reserves dedicated to our pipeline systems due to the cost of such evaluations and the lack of publicly available producer reserve information. Accordingly, we do not have estimates of total reserves dedicated to our assets, the average production declines of producer wells or the anticipated lives of producing reserves; therefore volumes of natural gas transported on our pipeline systems in the future could be more or less than we anticipate. See “Risk Factors —Risks Related to Our Business.”

Each of our operating segments is affected by the level of drilling in its operating area. During 2011, we saw considerable drilling activity in domestic shale plays, particularly in the Eagle Ford Shale, north Barnett Shale Combo and the Woodford Shale. Drilling activity in our conventional drilling areas has been minimal. As producers continue to focus on the unconventional shale plays, it remains unclear when they will undertake sustained increases in drilling activity throughout the conventional areas in which we operate. In the Powder River Basin, producers must “dewater” newly drilled coal-bed methane wells to draw the methane gas to the surface, which introduces a delay of twelve to eighteen months into the process of connecting newly drilled natural gas supplies. Both the effects of declining drilling activity on our Rocky Mountains systems due to the natural gas price environment and the recovery in volumes after producers resume drilling will be delayed because of dewatering. Dewatering is also required in the Hunton formation in Oklahoma, although the process used in that region generally requires less time to complete.

Texas

In Texas, we have increasingly focused on obtaining longer-term producer volume commitments and acreage dedications to secure natural gas supplies in support of our recent expansion projects. For example, our DK pipeline is supported by producer volume commitments and dedicated acreage.

During the year ended December 31, 2011, our Texas segment’s top five suppliers by volume of natural gas collectively accounted for approximately 30% of the natural gas delivered to our Texas systems during the period, with no individual producer accounting for 10% or greater of our consolidated cost of goods sold. Our Texas segment’s top five customers collectively accounted for 61% of our Texas segment’s revenue in 2011, with Dow Hydrocarbons and Resources accounting for 15% of our consolidated revenue.

Oklahoma

Our largest Oklahoma producer by volume has dedicated to us all of its production within a 1.1 million acre area under a long-term agreement. We also have dedications from other producers covering their production within approximately 500,000 acres in the aggregate.

During the year ended December 31, 2011, our Oklahoma segment’s top five producers by volume collectively accounted for approximately 65% of the natural gas delivered to our Oklahoma systems during the period with New Dominion LLC accounting for 14% of our consolidated cost of goods sold. Our Oklahoma segment’s top five customers collectively accounted for 90% of our Oklahoma segment’s revenue in 2011, with Oneok Hydrocarbon, L.P. and its affiliates accounting for 29% of our consolidated revenue.

 

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Rocky Mountains

Under Fort Union’s operating agreement, the owners of Fort Union established an area of mutual interest (“AMI”) covering approximately 2.98 million acres in the Powder River Basin and committed all gas production from the AMI to the Fort Union system up to the total capacity of the Fort Union system based on each owner’s total capacity rights.

During the year ended December 31, 2011, Fort Union’s top three shippers based on gathering fees accounted for approximately 95% of Fort Union’s revenue.

The owners of Bighorn established an approximately 3.8 million-acre AMI in the Powder River Basin, which provides that projects undertaken by the owners or their subsidiaries in the AMI must be conducted through Bighorn. Additionally, production from leases covering more than 800,000 acres of land within the Powder River Basin has been dedicated to the Bighorn Gathering system by other producers.

During the year ended December 31, 2011, Bighorn’s top two producers based on gathering fees collectively accounted for approximately 77% of Bighorn’s revenue.

Competition

The midstream industry is highly competitive. Competition is based primarily on the reputation, efficiency, flexibility, size, 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, transportation, compression, dehydration, treating, processing, NGL transportation and fractionation and condensate gathering and transportation. We believe that offering an integrated package of services allows us to compete more effectively for new natural gas supplies in our operating regions.

We face strong competition in connecting new natural gas supplies, developing organic growth projects and in pursuing acquisition opportunities as part of our long-term growth strategy. Our competitors include major interstate and intrastate pipelines, other natural gas gatherers and natural gas producers that gather, process and market natural gas and NGLs. In addition, Double Eagle Pipeline will compete with other companies that provide crude and condensate gathering, transportation and storage and related services. Our competitors may have capital resources and control supplies of natural gas, crude oil or condensate greater than ours.

Texas

We provide comprehensive services to natural gas producers in our Texas segment, including gathering, transportation, compression, dehydration, treating and processing and NGL and condensate transportation, fractionation and marketing. We believe our ability to furnish this full slate of services gives us an advantage in competing effectively for new supplies of natural gas because we can provide the services that producers, marketers and others require to connect their natural gas quickly and efficiently. For natural gas that exceeds the maximum carbon dioxide and NGL specifications for interconnecting pipelines and downstream markets, we believe that our treating and other processing and fractionation services are offered on competitive terms.

Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, DCP Midstream, Energy Transfer Partners and Targa Resources.

Oklahoma

We provide comprehensive services to natural gas producers in our Oklahoma segment, including gathering, transportation, compression, dehydration, treating, processing and, at our Paden plant, nitrogen rejection. We believe our ability to furnish this full slate of services gives us an advantage in competing effectively for new supplies of natural gas because we can provide the services that producers, marketers and others require to connect their natural gas quickly and efficiently.

 

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Most of our Oklahoma systems offer low-pressure gathering service, which is attractive to producers. We have made significant investments in limited-emissions, multi-stage compressors for our Oklahoma segment, which has allowed for quicker permitting and installation, thereby allowing us to provide the low pressure required by producers more efficiently. We believe this approach provides us a competitive advantage.

Our major competitors for natural gas supplies and markets in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, Atlas Pipeline, ONEOK Field Services, Hiland Partners, Enogex, MarkWest, Enerfin, Mustang Gas Products and Superior Pipeline.

Rocky Mountains

A significant portion of the gas on the Bighorn and Fort Union systems is dedicated under long-term gas gathering agreements.

Our major competitors for natural gas gathering supplies and markets in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy and Western Gas Resources. In addition, our major competitor in providing take away capacity from the Rocky Mountains segment is the Bison Interstate Pipeline.

Industry Overview

The midstream oil and gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets and consists of gathering, compression, dehydration, treating, conditioning, processing, transportation and fractionation, see diagram of the industry below.

 

LOGO

Midstream Services

Gathering. The gathering process begins with the drilling of wells into gas or oil bearing rock formations. Once an oil or gas well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small-diameter pipelines that collect oil, gas or condensate from points near producing wells for delivery to larger pipelines or trucks for further transportation.

Compression. Gathering systems are operated at pressures that will maximize the total throughput from all connected wells. Because wells produce at progressively lower field pressures as they age, it becomes increasingly difficult to deliver the remaining production in the ground against the higher pressure that exists in

 

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the connected gathering system. Natural gas compression is a mechanical process in which a volume of gas at an existing pressure is compressed to a desired higher pressure, allowing gas that no longer naturally flows into a higher-pressure downstream pipeline to be brought to market. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver gas into a higher-pressure downstream pipeline. If field compression is not installed, then the remaining natural gas in the ground will not be produced because it will be unable to overcome the higher gathering system pressure. In contrast, if field compression is installed, a declining well can continue delivering natural gas.

Natural gas dehydration. Natural gas is sometimes saturated with water, which must be removed because it can form ice and plug different parts of pipeline gathering and transportation systems and processing plants. Water in a natural gas stream can also cause corrosion when combined with carbon dioxide or hydrogen sulfide in natural gas, and condensed water in the pipeline can raise inlet pipeline pressure, causing a greater pressure drop downstream. Dehydration of natural gas helps to avoid these potential issues and to meet downstream pipeline and end-user gas quality standards.

Natural gas treating and blending. Natural gas composition varies depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations can be high in carbon dioxide or hydrogen sulfide, which may cause significant damage to pipelines and is generally not acceptable to end-users. To alleviate the potential adverse effects of these contaminants, many pipelines regularly inject corrosion inhibitors into the gas stream. Additionally, to render natural gas with high carbon dioxide or hydrogen sulfide levels to downstream pipeline quality, pipelines may blend the gas with gas that contains low carbon dioxide or hydrogen sulfide levels, or arrange for treatment to remove carbon dioxide and hydrogen sulfide to levels that meet pipeline quality standards. Natural gas can also contain nitrogen, which lowers the heating value of natural gas and must be removed to meet pipeline specifications.

Amine treating. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide, which allows it to absorb these impurities from the gas. After mixing, gas and amine are separated, and the impurities are removed from the amine by heating. The treating plants are sized by the amine circulation capacity in terms of gallons per minute.

Natural gas processing. Natural gas processing involves the separation of natural gas into downstream pipeline quality natural gas and a mixed NGL stream. The principal component of natural gas is methane, but most natural gas also contains varying amounts of heavier hydrocarbon components, or NGLs. Natural gas is described as lean or rich depending on its content of NGLs. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use because it contains NGLs and impurities. Natural gas processing not only separates the dry natural gas from the NGLs that would interfere with downstream pipeline transportation or other uses of the natural gas, but also extracts hydrocarbon liquids that can have higher value as NGLs. Removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics.

NGL fractionation. Fractionation is the process by which NGLs are separated into individual, more valuable components. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of ethylene and propylene and as a heating fuel, an engine fuel and an industrial fuel. Isobutane is used principally to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butylene (a key ingredient in synthetic rubber), as a blend stock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. Stabilized condensate is primarily used as a refinery feedstock for the production of motor gasoline and other products.

 

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NGLs are fractionated by heating mixed NGL streams and passing them through a series of distillation towers. Fractionation takes advantage of the differing boiling points of the various NGL products. As the temperature of the NGL stream is increased, the lightest (lowest boiling point) NGL product boils off the top of the tower where it is condensed and routed to a pipeline or storage. The mixture from the bottom of the first tower is then moved into the next tower where the process is repeated and a different NGL product is separated and stored. This process is repeated until the NGLs have been separated into their components. Because the fractionation process uses large quantities of heat, fuel costs are a major component of the total cost of fractionation.

Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to other pipelines, markets, industrial purchasers and utilities.

Oil and NGL transportation. Crude oil, condensate and NGLs are transported to market by means of pipelines, pressurized barges, railcar and tank trucks. The method of transportation used depends on, among other things, the existing resources of the transporter, the locations of the production points and the delivery points, cost-efficiency and the quantity being transported. Pipelines are generally the most cost-efficient means of transportation for large, consistent volumes of crude oil, condensate or NGLs.

Condensate handling. Condensate is a liquid hydrocarbon recovered from raw natural gas (either associated or not associated with crude oil production). Once condensate has been removed from the natural gas stream, it may require stabilization to reduce the Reid Vapor Pressure so that it may be transported to a refinery or a petrochemical facility to be used as feedstock. Stabilized condensate is routinely transported via tank truck, railcar, marine vessel or pipeline.

Midstream Contracts

Natural gas is gathered and processed in the industry pursuant to a variety of arrangements generally categorized (by the nature of the commodity price risk) as fee-based, percent-of-proceeds, percent-of-index and keep-whole. Contracts may rely solely on a single type of arrangement, but more often they combine elements of two or more, which helps the parties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. In addition, processing contracts sometimes include a “fixed recovery” concept, as described below. The terms of any individual contract will depend on a variety of factors, including gas quality and NGL content, pressures of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements.

Fee-Based. Under these arrangements, the pipeline or processor generally is paid a fee per unit volume for services such as gathering, transporting, processing or fractionation. Revenue from fee-based arrangements is directly related to the volume of oil, condensate, natural gas or NGLs that flows through the midstream company’s systems and is not directly dependent on commodity prices. However, sustained low commodity prices could result in a decline in volumes and a corresponding decrease in fee revenue. These arrangements provide stable cash flows, but minimal if any upside in higher commodity price environments. Some fee-based arrangement involve firm volume commitments by the producer, under which the producer is obligated to pay fees (sometimes referred to as “deficiency fees”) for the committed volumes even if the producer’s physical deliveries are less. Typically deficiency fees become payable at the end of a quarter or year with respect to committed volumes for that period.

Percent-of-Proceeds. Under these arrangements generally, raw natural gas is gathered from producers at the wellhead, moved through the gathering system and then processed and sold at prices based on published index prices. Producers are paid based on an agreed percentage of the residue gas and NGLs multiplied by index prices or the actual sale prices. A similar type of arrangement, under which the processor shares only in specified percentages of the index-based value or actual sale proceeds for the NGLs, and the producer receives 100% of the index-based value or sale proceeds for the residue gas, is referred to as a “percent-of-liquids” arrangement.

 

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Margins from percent-of-proceeds and percent-of-liquids arrangements correlate directly with the prices of natural gas and NGLs, meaning that they provide upside to the processor in high commodity price environments but result in lower margins in low commodity price environments.

Percent-of-Index. Under percent-of-index arrangements, raw natural gas is purchased from producers at the wellhead at either a percentage discount to a specified index price or a weighted average sales price based on natural gas sales. The gas is then sold, or if the gas is processed, the resulting NGLs and residue gas are sold. For gas that is sold without processing, margins correlate directly with natural gas prices. If the gas is processed, the processor’s margin increases as the prices of NGLs increase relative to the price of natural gas and decrease as the prices of NGLs decrease relative to the price of natural gas, resulting in commodity exposure similar to that of a keep-whole arrangement.

Keep-Whole. Under these arrangements, raw natural gas is processed to extract NGLs, and the processor pays the producer the full thermal-equivalent volume of the raw natural gas received from the producer, either in the form of residue gas or its equivalent value. The processor is generally entitled to retain the extracted NGLs and sell them for its own account. Keep-whole margins are a function of the difference between the value of the NGLs extracted and the cost of the residue gas needed to replace the thermal equivalent volume of natural gas used in processing. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide significant upside in favorable commodity price environments but can result in losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs.

Many keep-whole arrangements have terms that reduce commodity price exposure in one or more ways, including (i) a fee-based, reduced-recovery arrangement that applies if the NGLs have a lower value than their thermal equivalent in natural gas, (ii) discounts to the applicable natural gas index price used to reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, or (iii) fees for ancillary services such as gathering, treating and compression.

Fixed Recoveries. Fee-based or percent-of-proceeds contracts sometimes include fixed recovery terms, which mean that the prices paid or products returned to the producer are calculated using an agreed NGL recovery factor, regardless of the volumes of NGLs actually recovered through processing. The processor negotiates the NGL recovery factor based generally on its expectations regarding operational factors such as plant capacity and efficiency and the average NGL content of natural gas delivered to the plant. If the processor’s actual recoveries differ from the agreed recovery factor, the processor’s margin will be affected to the extent of the difference. These arrangements can provide upside in high commodity price environments and also allow the processor to increase its margins by reducing recoveries in response to unfavorable NGL prices. Contracts providing for fixed recoveries allow the processor to benefit from increases in plant efficiency, which enhance the processor’s ability to respond to changing commodity prices. However, the processor could incur losses during favorable NGL price environments if its actual NGL recoveries fall below agreed NGL recovery factor due to plant inefficiencies or for other operational reasons.

Risk Management

We are exposed to market risks such as changes in commodity prices and interest rates. We use derivative instruments to mitigate the effects of these risks. In general, we attempt to hedge against the effects of changes in commodity prices or interest rates on our cash flow and profitability so that we can continue to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes. For a discussion of our risk management activities, please read Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

Regulation

In the ordinary course of business, we are subject to various laws and regulations, as described below. We believe that compliance with existing laws and regulations will not materially affect our financial position.

 

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Although we cannot predict how new or amended laws or regulations that may be adopted would impact our business, such laws, regulations or amendments could increase our costs and could reduce demand for natural gas and NGLs or crude oil, thereby reducing demand for our services.

Industry Regulation

FERC Regulation of Natural Gas Pipelines. We do not own any interstate natural gas pipelines, so FERC does not directly regulate the rates and terms of service associated with our operations. However, FERC’s regulations under the Natural Gas Policy Act of 1978 (the “NGPA”) and the Energy Policy Act of 2005 do affect certain aspects of our business and the market for our products.

Under the Energy Policy Act of 2005, FERC possesses regulatory oversight over natural gas markets, including the purchase, sale and transportation activities of non-interstate pipelines and other natural gas market participants. The Commodity Futures Trading Commission (the “CFTC”) also has authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. With regard to our physical purchases and sales of natural gas and NGLs, our gathering or transportation of these energy commodities and any related hedging activities that we undertake, we are required to observe these anti-market manipulation laws and related regulations enforced by FERC and/or the CFTC. These agencies hold substantial enforcement authority, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

FERC has adopted market-monitoring and annual reporting regulations intended to increase the transparency of wholesale energy markets, to protect the integrity of such markets, and to improve FERC’s ability to assess market forces and detect market manipulation. Certain of our operations are subject to FERC reporting requirements, including reporting of contract terms by intrastate Section 311 natural gas pipelines and reporting of aggregated annual volume and other information by natural gas wholesalers and purchasers.

FERC Regulation of NGL Pipelines. We own or operate NGL pipelines in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to FERC jurisdiction under the Interstate Commerce Act (the “ICA”) and the Energy Policy Act of 1992. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. We cannot guarantee that the jurisdictional status of our NGL facilities will remain unchanged, however. Should they be found jurisdictional, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay the use of rates that reflect increased costs, and may subject us to potentially burdensome and expensive operational, reporting and other requirements.

Intrastate Natural Gas Pipeline Regulation. We own an intrastate natural gas transmission facility in Texas. To the extent it transports gas in interstate commerce, this facility is subject to regulation by the FERC under Section 311 of the NGPA. Section 311 requires, among other things, that rates for such interstate service (which may be established by the applicable state agency, in our case the Texas Railroad Commission, or the “TRRC”) be “fair and equitable” and permits the FERC to approve terms and conditions of service.

Natural Gas Gathering Regulation. Section 1(b) of the Natural Gas Act (“NGA”) exempts natural gas gathering facilities from FERC’s jurisdiction. We own or hold interests in a number of natural gas pipeline systems in Texas, Oklahoma and Wyoming that we believe meet the traditional tests FERC has used to establish a pipeline system’s status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of our gathering facilities may be subject to change based on future determinations by FERC and the courts. Thus, we cannot guarantee that the jurisdictional status of our natural gas gathering facilities will remain

 

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unchanged. Should these gas gathering facilities be found jurisdictional, the FERC could require significant changes to the rates, terms and conditions of service on the affected pipelines and such facilities may be subject to potentially burdensome and expensive operational, reporting and other requirements.

In Texas, Oklahoma and Wyoming, the states in which our gathering operations take place, we are subject to state safety, environmental and service regulation. While our non-utility operations are not subject to direct state regulation of our gathering rates, we are required to offer gathering services on a non-discriminatory basis. In general, the non-discrimination requirement is monitored and enforced by each state based upon filed complaints.

We are also subject to state ratable take and common purchaser statutes in these states. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without discriminating in favor of one producer over another producer or one source of supply over another source of supply.

State Utility Regulation. Some of our operations in Texas (specifically, our intrastate transmission pipeline and several of our gathering systems) are subject to the Texas Gas Utility Regulatory Act, as implemented by the TRRC. Generally, the TRRC has authority to ensure that rates charged for natural gas sales or transportation services are just and reasonable. None of our operations in Oklahoma or Wyoming are regulated as public utilities by the Oklahoma Corporation Commission (“OCC”) or the Wyoming Public Service Commission (“WPSC”).

Sales of Natural Gas and NGLs. The prices at which we buy and sell natural gas currently are not subject to federal regulation, and except as noted above with respect to our gas utility operations, are not subject to state regulation. The prices at which we sell NGLs are not subject to federal or state regulation.

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.

Environmental and Occupational Health and Safety Matters

Our operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, transporting or fractionation of natural gas, NGLs, condensate and other products is subject to stringent and complex laws and regulations pertaining to occupational health and safety and the environment. As an owner or operator of these facilities, we must comply with these laws and regulations at the federal, regional, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

   

Requiring us to acquire permits or other approvals to conduct regulated activities;

 

   

restricting the way we can handle or dispose of wastes;

 

   

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

 

   

imposing specific health and safety criteria addressing worker protection;

 

   

requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operators; and

 

   

causing us to incur capital cost to construct, maintain and upgrade equipment and facilities.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining future operations. We believe that our operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing environmental laws and regulations will not have a material

 

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adverse effect on our business, financial position or results of operations. However, the trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. As a result, 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.

The following is a summary of the more significant current environmental and occupational health and safety laws and regulations to which our business operations are subject:

Hazardous Substances and Wastes. Our operations are subject to the federal Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and non-hazardous solid waste. Under the authority of the U.S. Environmental Protection Agency (“EPA”), most states administer some or all of the RCRA, sometimes in conjunction with their own, more stringent requirements. In the course of our operations, we generate petroleum hydrocarbon wastes and ordinary industrial wastes that may be regulated as hazardous waste.

The Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA”), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum and natural gas are excluded from CERCLA’s definition of “hazardous substance,” in the course of our ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to strict and, under certain circumstances, joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources and for the costs of certain health studies.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, field compression and processing of natural gas, as well as the gathering of natural gas or crude oil. Although we used operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or wastes have been disposed of or released on or under some properties owned or leased by us or on or under other locations where such substances have been taken for disposal. Some of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove previously disposed wastes (including waste disposed of by prior owners or operators), remediate contaminated property (including groundwater contamination) or perform remedial closure operations to prevent future contamination. As of December 31, 2011, we have not received notification that any of our properties has been determined to be a current Superfund site under CERCLA.

Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations restrict emissions of air pollutants from various industrial sources, including our processing plants and 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 expected to produce air emissions or result in the increase of existing air emissions, obtain and comply with air permits containing various emissions and operational limitations, and use specific emission control technologies to limit emissions. In addition, future amendment of the Clean Air Act or comparable state laws may cause us to incur capital expenditures for installation of air pollution control equipment and to encounter construction delays while applying for and receiving new or amended permits. For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, new leak

 

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detection requirements for natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012. While we may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions, we currently do not believe that our operations will 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 (“GHGs”) present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. These EPA rules could adversely affect our operations and restrict or significantly delay our ability to obtain air permits for new or modified facilities. Moreover, because the EPA assumed responsibility for issuing construction and operating permits for GHG emissions in Texas in December 2010, those two permitting programs are now subject to dual sets of approvals at the state and federal levels. This division of construction and operating permit authority between the EPA and the Texas Commission on Environmental Quality may cause our Texas operations to experience added and potentially significant delays in obtaining permit coverages.

The EPA also adopted rules requiring the monitoring and reporting of GHG emissions from specific sources in the United States, including, among others, certain onshore natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations. In addition, Congress from time to time considers legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that require reporting of GHGs or otherwise limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate.

Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate change that could have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our midstream operations.

Water Discharges. Our operations are subject to the Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into state and federal waters. The discharge of pollutants, including petroleum hydrocarbon discharges resulting from a spill or leak incident, is prohibited unless authorized by a permit or other agency approval. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by a permit. Any unpermitted release of pollutants from our pipelines or facilities could result in administrative, civil and criminal penalties and significant remedial obligations.

Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel fuel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting,

 

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disclosure, or well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers’ operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for our gathering, processing and fractionation services. In addition, several governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing activities. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is planning to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, which events could delay or curtail production of natural gas by exploration and production operators, some of which may be our customers, and thus reduce demand for our midstream services.

Pipeline Safety. Our natural gas and NGL pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”), with respect to natural gas and the Hazardous Liquids Pipeline Safety Act of 1979 (“HLPSA”), with respect to hazardous liquids (including NGLs) pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. These pipeline safety laws are subject to further amendment if deemed necessary after study, with the potential for more onerous obligations and stringent standards being imposed on pipeline owners and operators. For example, on January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), which act requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, and leak detection system installation. The 2011 Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas, and increases the maximum penalty for violation of pipeline safety regulations from $1 million to $2 million. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

Our pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (“PIPES”). The DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), has established a series of rules which require pipeline operators to develop and implement integrity management programs for natural gas and hazardous liquid pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. In addition, pursuant to authorization granted by PIPES, the DOT’s regulatory coverage extends to certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified “unusually sensitive areas,” including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species or other ecological resources. Safety requirements imposed by this extended coverage include pipeline corrosion and third-party damage concerns but

 

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do not include pipeline integrity management criteria. Moreover, future amendment of these DOT rules may result in the implementation of more stringent pipeline safety standards that could cause us to incur increased operating costs, which costs could be significant. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, (i) revising the definitions of “high consequence areas” and “gathering lines”; (ii) strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed; (iii) strengthening requirements on the types of gas transmission pipeline integrity assessment methods that may be selected for use by operators; (iv) imposing gas transmission integrity management requirements on onshore gas gathering lines; (v) requiring the submission of annual, incident and safety-related conditions reports by operators of all gathering lines; and (vi) enhancing the current requirements for internal corrosion control of gathering lines.

Also, the TRRC and the OCC have adopted regulations similar to existing DOT regulations for intrastate natural gas and hazardous liquid gathering and transmission lines, while the Wyoming Public Service Commission has done the same for intrastate natural gas gathering and transmission lines but not hazardous liquid lines.

Endangered Species. The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. While some of our facilities may be located in, or otherwise serve, areas that are designated as habitat for endangered or threatened species, we believe that we are in substantial 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 areas. For example, in March 2010, the U.S. Department of the Interior (“DOI”) considered listing the sage grouse, a ground-dwelling bird that inhabits portions of the Rocky Mountains region, including Wyoming, where we have natural gas gathering operations, as an endangered species under the ESA. An Endangered Species Act designation could result in broad conservation measures restricting or even prohibiting natural gas exploration and production and expansion of our natural gas gathering activities in affected areas. The DOI determined that that sage grouse qualified for protection under the ESA but deferred listing it as endangered because of higher-priority listing commitments. Rather, executive orders were issued by Wyoming then-Governor Dave Freudenthal in 2010 and, more recently, by Wyoming current Governor Matt Mead that provided core areas of protection for the sage grouse, some of which affect areas near Bighorn’s and Fort Union’s gathering systems. Developers of oil and natural gas activity in protected areas must demonstrate how their activities will not diminish sage grouse populations in these areas. The determination by the DOI to defer listing of the sage grouse as endangered is subject to litigation, with at least one environmental organization legally challenging the deferral of such a listing. Moreover, the federal Bureau of Land Management and the State of Wyoming are pursuing separate strategies to maintain and enhance sage grouse habitat.

In addition, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency’s 2017 fiscal year. The designation of the sage grouse or of other previously unprotected species as threatened or endangered in areas where we conduct operations or plan to construct pipelines or facilities could cause us to incur increased costs arising from species protection measures or could result in limitations on our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.

Occupational Health and Safety. We are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that certain information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements.

 

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Office Facilities

We lease our executive offices in Houston, Texas, and Tulsa, Oklahoma. In connection with a decision to move commercial activities for our Rocky Mountains segment to our Tulsa office, we closed our Englewood, Colorado office in February 2012. We also lease property or facilities for some of our field offices.

Employees

As of December 31, 2011, we had 388 full-time employees and 6 part-time employees. None of our employees are covered by collective bargaining agreements. We consider our relations with our employees to be good.

Available Information

We file annual, quarterly and other reports and other information with the Securities and Exchange Commission (“SEC”) under the Securities Exchange Act of 1934 (the “Exchange Act”). You may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. You may obtain additional information about the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC, including us.

We also make available free of charge on or through our website (http://www.copano.com) or through our Investor Relations group (713-621-9547), our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other information statements and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information on our website is not incorporated by reference into this report.

 

Item 1A. Risk Factors

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described below, which could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operations could be adversely affected.

Risks Related to Our Business

We may not have sufficient cash after establishment of cash reserves to pay cash distributions at the current level.

We may not have sufficient cash each quarter to pay distributions at the current level. Under our limited liability company agreement, we set aside any cash reserve necessary for the conduct of our business before making a distribution to our unitholders. The amount of cash we have available for distribution is more a function of our cash flow than of our net income, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and may not make cash distributions during periods when we record net income.

The amount of cash we can distribute principally depends upon the cash we generate from operations, which will fluctuate from quarter to quarter based on, among other things:

 

   

the amount of natural gas gathered and transported on our pipelines;

 

   

the volume and NGL content of natural gas we process, and the volume of NGLs we fractionate;

 

   

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

 

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the fees we pay to third parties for their services;

 

   

the prices of natural gas, NGLs, condensate and crude oil;

 

   

the relationship between natural gas and NGL prices;

 

   

the relationship between Mont Belvieu and Conway NGL prices;

 

   

the level of our operating costs and the impact of inflation on those costs; and

 

   

the weather in our operating areas.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

   

the amount of capital we spend on projects, the profitability of such projects and the timing of the associated cash flow;

 

   

the operational performance and efficiency of our assets, including our plants and equipment;

 

   

the cost of any acquisitions we make;

 

   

the effectiveness of our hedging program;

 

   

the creditworthiness of our hedging and other contract counterparties;

 

   

the timing (quarterly or annual) of our producers’ obligations to make volume deficiency payments to us;

 

   

our ability to borrow money and access capital markets on acceptable terms;

 

   

our debt service requirements;

 

   

fluctuations in our working capital needs;

 

   

restrictions on distributions imposed by our revolving credit facility and the indentures governing our senior unsecured notes;

 

   

restrictions on distributions by entities in which we own interests;

 

   

the amount of cash reserves established by our Board of Directors for the proper conduct of our business; and

 

   

prevailing economic conditions.

Some of the factors described above are beyond our control. If we decrease distributions, the market price for our units may be adversely affected.

Our cash flow and profitability depend upon prices and market demand for natural gas, oil and NGLs, which are beyond our control and can be volatile.

Our cash flow and profitability are affected by prevailing NGL and natural gas prices, and we are subject to significant risks due to fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to recur periodically.

We derive approximately half of our gross margin from contracts with terms that are commodity price sensitive. As a result, our cash flow and profitability depend to a significant extent on the prices at which we buy and sell natural gas and at which we sell NGLs and condensate. The markets and prices for natural gas and NGLs depend upon many factors beyond our control. These factors include supply and demand for oil, natural gas, liquefied natural gas (“LNG”), nuclear energy, coal and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

 

   

the impact of weather on the demand for oil and natural gas;

 

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the levels of domestic oil and natural gas production and NGL extraction;

 

   

storage levels for oil, natural gas, LNG and NGLs;

 

   

the availability of imported oil, natural gas, LNG and NGLs;

 

   

international demand for LNG, oil and NGLs and NGL derivative products such as ethylene and propylene;

 

   

actions taken by foreign oil and gas producing nations;

 

   

the availability of takeaway and delivery infrastructure for natural gas, NGLs and condensate;

 

   

the availability of downstream NGL fractionation facilities;

 

   

our proximity to markets for natural gas, condensate and NGLs and the degree to which markets are accessible generally;

 

   

the availability and marketing of competitive fuels;

 

   

the impact of energy conservation efforts; and

 

   

the extent of governmental regulation and taxation.

Changes in commodity prices may also indirectly impact our profitability by influencing drilling activity and well operations, and thus the volume of natural gas we gather and process. This volatility may cause our gross margin and cash flows to vary widely from period to period. We use commodity derivative instruments to hedge our exposure to commodity prices, but these instruments also are subject to inherent risks. Please read “—Our hedging activities do not eliminate our exposure to commodity price and interest rate risks and may reduce our cash flow and subject our earnings to increased volatility.”

Because of the natural decline in production from existing wells, our success depends on our ability to continually obtain new supplies of natural gas and NGLs.

Our pipeline systems and processing or fractionation facilities are connected to or dependent on natural gas fields and wells from which the 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 volumes on our pipeline systems and inlet volumes at our processing plants, we must continually obtain new supplies of natural gas and NGLs. The primary factors affecting our ability to do so include the level of successful drilling activity near our gathering systems and our ability to compete with other midstream service providers for new natural gas supplies.

Fluctuations in energy prices can greatly affect drilling and production rates and investments by third parties in the development of new oil and gas reserves. Drilling activity generally decreases as oil or gas prices decrease, or in the case of rich gas drilling supported by NGL prices, as NGL prices decrease. We have no control over the level of drilling activity in the areas of our operations, the amount of reserves underlying the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things, prevailing and projected energy prices, drilling costs, the availability of drilling rigs, equipment, materials and labor for drilling and completing wells, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

We face strong competition in acquiring new natural gas supplies. Competitors to our pipeline operations include major interstate and intrastate pipelines, and other natural gas gatherers. Competition for natural gas supplies is primarily based on the location of pipeline facilities, access to related services such as processing and NGL handling, contract terms, reputation, efficiency, flexibility and reliability.

If we are unable to maintain or increase the throughput on our pipeline systems because of decreased drilling activity, production declines or competitive pressures, or for any other reason, then our business, results of operations, financial condition and ability to make cash distributions to our unitholders will be adversely affected.

 

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We generally do not obtain reservoir engineering reports evaluating reserves dedicated to our pipeline systems; therefore, volumes of natural gas transported on our pipeline systems in the future could be less than we anticipate, which may cause our revenues and operating income to be less than we expect.

We generally do not obtain reservoir engineering reports evaluating natural gas reserves connected to our pipeline systems due to producers’ general unwillingness to provide reserve information, as well as the cost of such evaluations. Accordingly, we do not have estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of reserves connected to our pipeline systems is less than we anticipate and we are unable to secure additional sources of natural gas, the volumes of natural gas that we gather and process would likely decline. A sustained decline in natural gas volumes would cause our revenues to be less than we expect, which could have a material adverse effect on our business, financial condition and our ability to make cash distributions to you.

We rely on third-party pipelines and other facilities in providing service to our customers. If one or more of these pipelines or facilities were to become capacity-constrained or unavailable, our cash flows, results of operations and financial condition could be adversely affected.

Our ability to provide service to our customers depends in part on the availability, proximity and capacity of third-party pipeline, processing and other facilities, and because we do not own or operate these facilities, their continuing operation or availability is not within our control. For example, we rely on Kinder Morgan’s Laredo-to-Katy pipeline to transport natural gas from Eagle Ford Gathering and several of our Texas gathering systems to our Houston Central complex, and we rely on Dow Hydrocarbon and Formosa to take delivery of NGLs from Houston Central. We rely on ONEOK Hydrocarbon to take delivery of NGLs from our Saint Jo plant and from several of our Oklahoma processing plants. We also depend on other third-party processing plants, pipelines and other facilities to provide our customers with processing, delivery, fractionation or transportation options.

Like us, these third-party service providers are subject to risks inherent in the midstream business, including capacity constraints, natural disasters and operational, mechanical or other hazards, as well as service interruptions for scheduled maintenance. The curtailments arising from these and similar circumstances may last from a few days to several months. NGL fractionation and transportation facilities and trucking services on which we depend are subject to increasing capacity constraints. Also, some third-party pipelines have minimum gas quality specifications that at times may limit or eliminate our transportation options.

If any of these facilities becomes unavailable or limited in its ability to provide services on which we depend, our cash flow and results of operations could be adversely affected. We would likely incur higher fees or other costs in arranging for alternatives. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary processing and transportation facilities, would interfere with our ability to serve our customers. A delay, prolonged interruption or reduction of service on Kinder Morgan’s pipeline or at Dow Hydrocarbon, Formosa, ONEOK Hydrocarbon, or another pipeline or facility on which we depend could hinder our ability to contract for additional natural gas and condensate services.

Constructing new assets subjects us to risks of project delays, cost overruns and lower-than-anticipated volumes of natural gas, NGLs or condensate once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations.

One of the ways we grow our business is by constructing additions or modifications to our existing facilities. We also construct new facilities, either near our existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal and operational uncertainties, many of which are beyond our control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources.

We may be unable to complete construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on our business and results of operations. Moreover, we may not receive any

 

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material increase in operating cash flow from a project for some time. For instance, if we expand a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully operational. In addition, our cash flow from a project may be delayed or may not meet our expectations. Our project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, economic and other uncertainties. Recently, we have experienced a delay in starting up our cryogenic processing upgrade at our Houston Central complex, and as a result, our cryogenic processing facilities have been down for longer than we expected. Our ability to achieve our expected NGL recoveries is dependent on the successful completion of the cryogenic upgrade. We expect that our margins and operating performance for the first quarter of 2012 will be negatively impacted as a result of this project delay.

We rely in part on estimates from producers regarding of the timing and volume of anticipated oil, gas or condensate production. Production estimates are subject to numerous uncertainties, all of which are beyond our control. These estimates may prove to be inaccurate, and new facilities may not attract sufficient volumes to achieve our expected cash flow and investment return.

We also construct assets in reliance on firm capacity commitments for third-party processing or fractionation downstream of our facilities. For example, we made processing commitments at our Houston Central complex and constructed the Liberty NGL pipeline through our joint venture with Energy Transfer in reliance on Formosa’s capacity commitment to us, which requires Formosa to expand its facilities. If Formosa is unable to meet its commitment to us, or if other third-party facilities are not available when we expect them, our cash flows and results of operations would be adversely affected.

Competition could negatively affect us.

Our industry is highly competitive. Our competitors may expand or construct midstream systems that would create additional competition for the services we provide to our customers. Some of our competitors are large companies that have greater financial resources and access to supplies of natural gas and NGLs than we do. We frequently have one or more competitors in the supply basins and markets that we are connected to. This includes new large pipeline systems (such as the Bison pipeline near Fort Union) that have recently been constructed near our assets, and growing competition in the markets that we serve. In addition, our customers may develop their own midstream systems in lieu of using ours. This competition could result in our inability to obtain new supplies of natural gas and NGLs, renew contracts and to maintain rates and transportation volumes, any of which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Competition for hiring experienced personnel, particularly in the engineering, field operations, accounting and financial reporting, information technology, tax and land departments, has been strong. In addition, competition to acquire attractive midstream assets has been strong. We may often be outbid by competitors in our attempts to make acquisitions. Our inability to compete effectively in hiring or making acquisitions could have a material adverse impact on our ability to grow.

We are exposed to the credit risk of our customers and other counterparties. A general increase in nonpayment and nonperformance by counterparties could adversely affect our cash flows, results of operations and financial condition.

Risks of nonpayment and nonperformance by our counterparties are a major concern in our business. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers and other counterparties, such as our lenders and hedging counterparties. Our shift toward a more fee-based contract portfolio means that we are increasingly reliant on the creditworthiness of customers who make fee-based volume commitments to us. Many of our customers finance their activities through cash flow from operations or debt or equity financing, all

 

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of which are subject to adverse changes in commodity prices and economic and market conditions. When commodity prices have been unfavorable for an extended period, some of our customers have experienced a combination of lower cash flow due to commodity prices, reduced borrowing bases under reserve-based credit facilities and reduced availability of debt or equity financing. These factors may result in a significant reduction in our customers’ liquidity and ability to pay us or otherwise perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own credit, operating and regulatory risks, which increases the risk that they may default on their obligations to us.

Any increase in nonpayment and nonperformance by our counterparties, either as a result of financial and economic conditions or otherwise, could have an adverse impact on our operating results and could adversely affect our liquidity.

If we make acquisitions that do not perform as expected, our financial performance may be negatively impacted.

Our business strategy includes making acquisitions that we anticipate would increase the cash available for distribution to our unitholders. As a result, from time to time, we evaluate and pursue assets and businesses that we believe complement our existing operations or expand our operations into new regions where our growth strategy can be applied. We cannot assure you that we will be able to complete acquisitions in the future or achieve the desired results from any acquisitions we do complete. In addition, failure to successfully integrate our acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions potentially involve numerous risks, including:

 

   

operating a significantly larger combined organization and adding operations;

 

   

difficulties in integrating the assets and operations of the acquired businesses, especially if the assets acquired are in a new type of midstream business or a new geographic area;

 

   

the risk that natural gas production expected to support the acquired assets may not be of the anticipated magnitude or may not be developed on the anticipated timetable, or at all;

 

   

the loss of significant producers or markets or key employees from the acquired businesses;

 

   

diversion of management’s attention from other business concerns;

 

   

failure to realize expected profitability or growth;

 

   

failure to realize any expected synergies and cost savings;

 

   

exposure to increased competition;

 

   

coordinating geographically disparate organizations, systems and facilities;

 

   

coordinating or consolidating information technology, compliance under the Sarbanes-Oxley Act of 2002 and other administrative or compliance functions; and

 

   

a decrease in liquidity and increased leverage as a result of using significant amounts of available cash or debt to finance an acquisition.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Because of these risks and challenges, even when we make acquisitions that we believe will increase our ability to distribute cash, those acquisitions may nevertheless reduce our cash from operations on a per unit basis. This could result in lower distributions to our common unitholders and make compliance with financial covenants under our debt agreements more difficult, and, if an acquisition’s performance does not improve, could ultimately require us to record an impairment of our interest in the acquired company or assets. Although our

 

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capitalization and results of operations may change significantly following an acquisition, you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

Our substantial indebtedness could limit our operating and financing flexibility and impair our ability to fulfill our obligations.

We have substantial indebtedness. As of February 17, 2012 and in addition to liabilities related to our risk management activities, we had total indebtedness of $852.9 million, including our senior unsecured notes and our revolving credit facility, and available borrowing capacity under our revolving credit facility was approximately $386.0 million. We may incur significant additional indebtedness and other financial obligations in the future. Our substantial indebtedness and other financial obligations could have important consequences to you. For example, these obligations could:

 

   

require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general company requirements;

 

   

make it more difficult for us to satisfy our debt service requirements or comply with financial or other covenants in our debt agreements;

 

   

impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general company purposes or other purposes;

 

   

result in higher interest expense if interest rates increase;

 

   

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

 

   

place us at a disadvantage relative to any competitors that have proportionately less debt or lower borrowing costs.

If we are unable to meet our debt service and other financial obligations or comply with our debt covenants, we could be forced to restructure or refinance our indebtedness, in which case our lenders could require us to suspend cash distributions, or seek additional equity capital or sell assets. We may be unable to obtain such refinancing or equity capital or sell assets on satisfactory terms, if at all. Failure to meet our debt service and other financial obligations could result in defaults under our debt agreements, which, if not cured or waived, would lead to acceleration of our debt and other financial obligations. If we were unable to repay those obligations, our lenders could initiate a bankruptcy proceeding or liquidation proceeding or proceed against any collateral.

Restrictive covenants in the agreements governing our indebtedness may reduce our operating flexibility.

The indentures governing our outstanding senior unsecured notes contain various covenants that limit our ability to, among other things:

 

   

sell assets;

 

   

pay distributions on, redeem or repurchase our equity interests or redeem or repurchase our subordinated debt, if any;

 

   

make investments;

 

   

incur or guarantee additional indebtedness or issue preferred units;

 

   

create or incur certain liens;

 

   

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

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consolidate, merge or transfer all or substantially all of our assets;

 

   

engage in transactions with affiliates;

 

   

create unrestricted subsidiaries;

 

   

enter into sale and leaseback transactions; and

 

   

enter into letters of credit.

Our revolving credit facility contains similar covenants, as well as covenants that require us to maintain specified financial ratios and satisfy other financial conditions. The restrictive covenants in our indentures and our revolving credit facility could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or in the economy in general, or conduct operations.

In addition, Fort Union, in which we own a 37.04% interest, has debt outstanding under an agreement that includes, among other customary covenants and events of default, a limitation on its ability to make cash distributions. Fort Union can distribute cash to its members only if its ratio of net operating cash flow to debt service is not less than 1.25 to 1.00 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash to us, and its lenders could accelerate its repayment obligations, both of which would adversely affect our cash flow.

Our ability to obtain funding under our revolving credit facility could be impaired by conditions in the financial markets.

We rely on our revolving credit facility to finance a significant portion of our capital expenditures. Our ability to borrow under our revolving credit facility is subject to conditions in the financial markets, including the solvency of institutional lenders.

If we are unable to access funds under our revolving credit facility, we would need to meet our capital requirements using other sources which, depending on economic conditions, may not be available on acceptable terms. If the cash generated from our operations or the funds we are able to obtain under our revolving credit facility or other sources of liquidity are not sufficient to meet our capital requirements, then we may need to delay or abandon expansion projects or other business opportunities, which could have a material adverse effect on our results of operations and financial condition.

We may be unable to raise capital necessary to fully execute our business strategy on satisfactory terms, or at all.

Our business strategy contemplates pursuing capital projects and acquisitions. We regularly consider and enter into discussions regarding strategic projects or transactions that we believe will present opportunities to pursue our growth strategy. We will require substantial new capital to finance strategic acquisitions or to complete significant organic expansion or greenfield projects. If capital becomes too expensive, our ability to develop or acquire accretive assets will be limited.

The availability and cost of debt and equity capital are subject to general economic conditions and perceptions about the stability of financial markets and the solvency of counterparties. Adverse changes in these factors likely would result in higher interest rates and deterioration in the availability and cost of debt and equity financing. Any limitations on our access to capital will impair our ability to execute our growth strategy.

If capital on acceptable terms is not available to us, our inability to fully execute our growth strategy, otherwise take advantage of business opportunities or respond to competitive pressures could have a material adverse effect on our results of operations and financial condition. Illiquid capital markets could also limit investment and development by third parties, such as producers and end-users, which could indirectly affect our ability to fully execute our business strategy.

 

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Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

Our operations are subject to the many hazards inherent in the gathering, compression, treating, processing, transportation and fractionation of natural gas and NGLs, including:

 

   

damage to pipelines, pipeline blockages and damage to related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, extreme weather conditions and other natural disasters and acts of terrorism;

 

   

inadvertent damage from motor vehicles, construction or farm equipment;

 

   

leaks of natural gas, NGLs, condensate and other hydrocarbons;

 

   

environmental hazards, such as oil and NGL releases, pipeline or tank ruptures, and unauthorized discharges of pollutants into the surface and subsurface environment;

 

   

operator error; and

 

   

fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. In addition, mechanical malfunctions, undetected leaks in pipelines, faulty measurement or other errors may result in significant costs or lost revenues. Our assets and operations are primarily concentrated in south Texas and north Texas regions and in southwest Louisiana, central and eastern Oklahoma and in Wyoming, and a natural disaster or other hazard affecting any of these areas could have a material adverse effect on our operations, even if our own facilities are not directly affected.

There can be no assurance that insurance will cover all damages and losses resulting from these types of natural disasters. We are not fully insured against all risks incident to our business. In accordance with typical industry practice, we generally 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 accidents that might occur, other than those considered to be sudden and accidental. Our business interruption insurance provides limited coverage for lost revenues arising from physical damage to our processing plants and certain third-party facilities on which we depend, subject to deductibles and time and dollar limitations. If a significant accident or event occurs that is not fully insured, our operations could be temporarily or permanently impaired, and our liabilities and expenses could be significant.

Due to our limited asset diversification, adverse developments in our gathering, transportation, processing and related businesses would have a significant impact on our results of operations.

Substantially all of our revenues are generated from our midstream services business, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas, crude oil, NGLs and condensate. Furthermore, substantially all of our assets are located in Texas, Oklahoma, Wyoming and Louisiana. Due to our limited diversification in asset type and location, an adverse development in the midstream business or in one or more of these areas would have a significantly greater impact on our cash flows, results of operations and financial condition than if we maintained more diverse assets.

We own interests in limited liability companies and a general partnership in which third parties also own interests, which limits our ability to influence significant business decisions affecting these entities.

In addition to our wholly owned subsidiaries, we own interests in a number of entities in which third parties also own an interest. These interests include our:

 

   

62.5% interest in Webb Duval;

 

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majority interest in Southern Dome;

 

   

51% interest in Bighorn;

 

   

37.04% interest in Fort Union;

 

   

50% interest in Eagle Ford Gathering;

 

   

50% interest in Liberty Pipeline Group; and

 

   

50% interest in Double Eagle Pipeline.

We serve each of these entities as operator, managing member or both, but we do not control any of them. Our ability to make certain substantive business decisions with respect to each is subject to the majority or unanimous approval of the owners or, in the case of Bighorn, of a management committee to which we have the right to appoint 50% of the members. Examples of decisions that require approval include significant expenditures or contractual commitments, the construction or acquisition of assets, borrowing money or otherwise raising capital and transactions not in the ordinary course of business, among others. Differences in views among the owners of any of these entities could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the entity involved and, in turn, the amounts and timing of cash from operations distributed to its members or partners, including us.

In addition, we do not control the day-to-day operations of Fort Union. Our lack of control over Fort Union’s day-to-day operations and the associated costs of operations could result in our receiving lower cash distributions than we anticipate, which could reduce our cash flow available for distribution to our unitholders.

We do not own all of the land on which our pipelines, plants and other facilities are located, so our growth projects and operations could be disrupted by actions of the landowners.

We lease the sites on which some of our plants and other facilities are located, and we obtain rights-of-way to construct and operate our pipelines on land owned by third parties and governmental agencies for specified periods of time. We may be unable to obtain rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other expansion opportunities. Additionally, acquiring rights-of-way or lease renewals may be more expensive than we anticipate. If a significant existing lease or significant existing right-of-way contracts lapse, are terminated or are determined to be invalid, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use. Our inability to obtain or to renew right-of-way contracts or leases could have a material adverse effect on our business, results of operations and financial condition and our ability to make cash distributions.

Failure of the natural gas, NGLs, condensate or other products produced at our plants or shipped on our pipelines to meet the specifications of interconnecting pipelines or markets could result in curtailments by the pipelines or markets.

The markets and pipelines to which we deliver natural gas, NGLs, condensate or other products typically establish specifications for the products that they are willing to accept. These specifications include requirements such as hydrocarbon dewpoint, compositions, temperature, and foreign content (such as water, sulfur, methane, carbon dioxide, nitrogen and hydrogen sulfide), and these specifications can vary by product, pipeline or markets. If the total mix of a product that we deliver to a pipeline or market fails to meet the applicable product quality specifications, the pipeline or market may refuse to accept all or a part of the products scheduled for delivery to it or may invoice us for the costs to handle the out-of-specification products. In those circumstances, we may be required to find alternative markets for that product or to shut-in the producers of the non-conforming natural gas that is causing the products to be out of specification, potentially reducing our throughput volumes or revenues. Changes in product quality specifications or changes in the quality of gas we receive from producers could

 

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reduce our throughput volumes or require us to incur additional handling costs or significant capital costs for new equipment such as nitrogen rejection or amine treating facilities. We may be unable to recover these costs through increased revenues.

Our hedging activities do not eliminate our exposure to commodity price and interest rate risks and may reduce our cash flow and subject our earnings to increased volatility.

Our operations expose us to fluctuations in commodity prices, and our revolving credit facility exposes us to fluctuations in interest rates. We use derivative financial instruments to reduce our sensitivity to commodity prices and interest rates, and the degree of our exposure is related largely to the effectiveness and scope of our hedging activities. We have hedged only portions of our variable-rate debt and expected NGL volumes. We continue to have direct interest rate and commodity price risk with respect to the unhedged portions, and our hedging strategies cannot offset volume risk.

Our ability to enter into new derivative instruments is subject to general economic and market conditions. The markets for instruments we use to hedge our commodity price and interest rate exposure generally reflect conditions in the underlying commodity and debt markets, and to the extent conditions in underlying markets are unfavorable, our ability to enter into new derivative instruments on acceptable terms will be limited. In addition, to the extent we hedge our commodity price and interest rate risks using swap instruments, we will forego the benefits of favorable changes in commodity prices or interest rates.

Our hedging activity may be ineffective or adversely affect our cash flow and liquidity, our earnings or both because, among other factors:

 

   

hedging can be expensive, particularly during periods of volatile prices or when hedging into extended future periods;

 

   

our counterparty in the hedging transaction may default on its obligation to pay; and

 

   

available hedges may not correspond precisely with the risks against which we seek protection. For example:

 

   

the duration of a hedge may not match the duration of the risk against which we seek protection;

 

   

variations in the index we use to price a commodity hedge may not adequately correlate with variations in the index we use to sell the physical commodity (known as basis risk); or

 

   

we may not produce or process sufficient volumes to cover swap arrangements we enter into for a given period. If our actual volumes are lower than the volumes we estimated when entering into a swap for the period, we might be forced to satisfy all or a portion of our derivative obligation without the benefit of cash flow from our sale or purchase of the underlying physical commodity.

Recently, basis risk has materialized into a significant factor affecting our hedges for Oklahoma NGLs. Our hedges are priced at Mont Belvieu, while the physical commodity is priced at Conway. The basis spread between these indices is at a historic high. While the prices we actually received for Oklahoma NGLs were below the strike prices for our hedges, we did not benefit because our hedges depend on Mont Belvieu prices, which remained above our hedge strike prices. Our financial statements may reflect gains or losses arising from exposure to commodity prices or interest rates for which we are unable to enter into fully economically effective hedges. In addition, the standards for cash flow hedge accounting are rigorous. Even when we engage in hedging transactions that are effective economically, these transactions may not be considered effective cash flow hedges for accounting purposes. Our earnings could be subject to increased volatility to the extent our derivatives do not continue to qualify as cash flow hedges, and, if we assume derivatives as part of an acquisition, to the extent we cannot obtain or choose not to seek cash flow hedge accounting for the derivatives we assume.

 

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The recent adoption of financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to hedge risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including businesses like ours, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), was signed into law by the President on July 21, 2010, and requires the Commodity Futures Trading Commission (the “CFTC”), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. In December 2011, the CFTC extended temporary exemptive relief from certain swap regulation provisions of the legislation until July 16, 2012. In its rulemaking under the Act, the CFTC has issued final regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions or derivative instruments would be exempt from these position limits. It is not possible at this time to predict when the CFTC will make these regulations effective. The Act may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivatives activities, although the application of those provisions to us is uncertain at this time. The Act may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivatives contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivatives contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our business, our financial condition, and our results of operations.

Our acquisitions could expose us to potential significant liabilities.

We generally assume the liabilities of entities that we acquire and may assume certain liabilities relating to assets that we acquire, including unknown and contingent liabilities. We perform due diligence in connection with our acquisitions and attempt to verify the representations of the sellers, but there may be pending, threatened, contemplated or contingent claims related to environmental, title, regulatory, litigation or other matters of which we are unaware. We may have indemnification claims against sellers for certain of these liabilities, as well as for disclosed liabilities, but our indemnification rights generally will be limited in amount and duration. Our right to indemnification also will be limited, as a practical matter, to the creditworthiness of the indemnifying party. If our right to indemnification is inadequate to cover the obligations of an acquired entity or relating to acquired assets, or if our indemnifying seller is unable to meet its obligations to us, our liability for such obligations could materially adversely affect our cash flow, operations and financial condition.

Federal, state or local regulatory measures could adversely affect our business.

Our pipeline transportation and gathering systems are subject to federal, state and local regulation. Most of our natural gas pipelines are gathering systems that are considered non-utilities in the states in which they are located. Several of our pipelines in Texas are subject to regulation as gas utilities by the TRRC. The states in which we operate have complaint-based regulation of natural gas gathering activities. Natural gas producers, shippers and other affected parties may file complaints with state regulators relating to natural gas gathering access and discrimination with regard to rates and terms of service, or, with respect to our gas utility pipelines in Texas, challenging the rates we charge for utility transportation service. Other state laws and regulations may not

 

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directly regulate our business, but may nonetheless affect the availability of natural gas for gathering, purchase, processing and sale, including state regulation of production rates and maximum daily production allowables from gas wells. A successful complaint, or new laws or regulatory rulings related to gathering, downstream quality specifications or natural gas utilities, could increase our costs or require us to alter our gathering or utility services charges and our business.

To the extent that our intrastate transmission pipeline in Texas transports natural gas in interstate commerce, the rates, terms and conditions of that transportation service are subject to regulation by the FERC pursuant to Section 311 of the NGPA. If our Section 311 rates are successfully challenged, if we are unable to include all of our costs in the cost of service approved in a future rate case, or if FERC changes its regulations or policies or establishes more onerous terms and conditions applicable to Section 311 service, our margins relating to this activity would be adversely affected.

We also have transportation contracts with interstate pipelines that are subject to FERC regulation. As a shipper on an interstate pipeline, we are subject to FERC requirements related to use of the interstate capacity. Any failure on our part to comply with the FERC’s regulations or an interstate pipeline’s tariff could result in the imposition of administrative, civil and criminal penalties.

Our physical purchases and sales of natural gas and NGLs, our gathering or transportation of these energy commodities, and any related hedging activities, must comply with applicable anti-market manipulation laws and related regulations enforced by the FERC and/or the CFTC. The FERC and the CFTC hold substantial enforcement authority under the anti-market manipulation laws and regulations, including the ability to assess civil penalties of up to $1 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

These and other new laws and regulations or any administrative or judicial re-interpretations of existing laws, regulations or agreements could impose increased costs and administrative burdens on us, and our business, results of operations and financial condition could be adversely affected. In addition, laws and regulations affecting producers to whom we provide our services could have adverse effects on us to the extent they affect production in our operating areas. For instance, the U.S. Supreme Court is adjudicating a dispute between the States of Montana and Wyoming over water rights in two rivers that flow through both states. Montana is asserting that Wyoming uses too much water from the Tongue and Powder Rivers pursuant to the Yellowstone River Compact, an agreement that both states entered into in 1950. Montana argues that the Compact applies to groundwater, and that coal bed methane production in Wyoming, which involves the pumping of large quantities of groundwater, is depleting the two rivers in violation of the Compact. Montana has asked the Supreme Court to declare Montana’s right to, and to order Wyoming to deliver, the waters of these two rivers to Montana in accord with the Compact. In a February 2010 ruling on Wyoming’s motion to dismiss, the special master appointed by the Supreme Court concluded that the Compact protects Montana from at least some forms of groundwater pumping but left the question of the exact circumstances under which groundwater pumping violates the Compact to subsequent proceedings in the case. Any decision by the Supreme Court that effectively limits the amount of groundwater pumped in connection with coal bed methane production in Wyoming may have significant adverse effects on natural gas production in affected areas of Wyoming and, correspondingly, on gathering services that Bighorn and Fort Union provide.

If producer drilling activity declines or is delayed due to increased costs or operating restrictions relating to regulation of hydraulic fracturing, we could be adversely affected.

Hydraulic fracturing is an important and common practice that producers use to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal

 

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regulatory authority under the Federal Safe Drinking Water Act over hydraulic fracturing involving the use of diesel additives. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Wyoming and Texas, have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our oil and natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our midstream services. In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. More recently, the EPA announced plans to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, which events could delay or curtail production of natural gas by exploration and production operators, some of which are our customers, and thus reduce demand for our midstream services.

A change in the characterization of some of our assets by federal, state or local regulatory agencies could adversely affect our business.

Section 1(b) of the NGA provides that the FERC’s rate and service jurisdiction does not extend to facilities used for the production or gathering of natural gas. “Gathering” is not specifically defined by the NGA or its implementing regulations, and there is no bright-line test for determining the jurisdictional status of pipeline facilities. Although some guidance is provided by case law, the process of determining whether facilities constitute gathering facilities for purposes of regulation under the NGA is fact-specific and subject to regulatory change. Additionally, our construction, expansion, extension or alteration of pipeline facilities may involve regulatory, environmental, political and legal uncertainties, including the possibility that physical changes to our pipeline systems may be deemed to affect their jurisdictional status.

The distinction between FERC-regulated interstate natural gas transmission services and federally unregulated gathering services has been the subject of litigation from time to time, as has been the line between intrastate and interstate transportation services. Thus, the classification and regulation of some of our natural gas gathering facilities and our intrastate transportation pipeline may be subject to change based on future determinations by the FERC and/or the courts. Should any of our natural gas gathering or intrastate facilities be deemed to be jurisdictional under the NGA, we could be required to comply with numerous federal requirements for interstate service, including laws and regulations governing the rates charged for interstate transportation services, the terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the initiation and discontinuation of services, the monitoring and posting of real-time system information and many other requirements. Failure to comply with all applicable FERC-administered statutes, rules, regulations and orders could result in substantial penalties and fines. It is also possible that our gathering facilities could be deemed by a relevant state commission or court, or by a change in law or regulation, to constitute intrastate pipelines subject to general state law and regulation of rates and terms and conditions of service. A change in jurisdictional status through litigation or legislation could require significant changes to the rates, terms and conditions of service on the affected pipeline, could increase the expense of providing service and adversely affect our business.

 

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The distinction between FERC-regulated common carriage of NGLs, and the non-jurisdictional intrastate transportation of NGLs, has also been the subject of litigation. To the extent any of our NGL assets is found to be subject to FERC jurisdiction, the FERC’s rate-making methodologies could limit our ability to set rates that we might otherwise be able to charge, could delay the use of rates that reflect increased costs and could subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.

Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for our midstream services.

In response to findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such 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 federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that requires certain construction and operating permit reviews for GHG emissions from certain large stationary sources. These EPA rules could adversely affect our operations and restrict or significantly delay our ability to obtain air permits for new or modified facilities. The EPA also adopted rules requiring the monitoring and reporting of GHG emissions from specific sources in the United States, including, among others, onshore oil and natural gas processing, transmission, storage, and distribution activities, which may include certain of our operations.

In addition, Congress from time to time considers legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the natural gas and NGLs we gather and process or fractionate.

We may incur significant costs and liabilities resulting from pipeline safety and integrity programs and related compliance efforts.

We are subject to DOT safety regulations with respect to our natural gas lines and our NGL lines, pursuant to which the DOT has established:

 

   

requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities;

 

   

mandatory inspections for all United States crude oil (including NGL) and natural gas transportation pipelines and gathering lines meeting certain operational risk and location requirements; and

 

   

additional safety requirements applicable to certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified unusually sensitive areas, which address primarily corrosion and third-party damage concerns.

Moreover, changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. Only recently, on January 3, 2012, President Obama signed the 2011 Pipeline Safety Act, which act, among other things, directs the Secretary of Transportation to conduct studies to determine the need for additional regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas and to then adopt new rules or standards as determined to be appropriate. These safety enhancement requirements and other provisions of this act could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our financial position or results of operations.

 

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We are subject to environmental laws and regulations that may expose us to significant costs and liabilities.

Our operation of gathering systems, plants and other facilities is subject to stringent and complex federal, regional, state and local environmental laws and regulations. These laws and regulations may restrict or impact our business activities in many ways, including requiring the acquisition of permits or other approvals to conduct regulated activities, restricting the manner in which we dispose of wastes, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with pollution control requirements. 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 remedial requirements and the issuance of orders enjoining future operations. Certain environmental statutes impose strict and, under certain circumstances, joint and several liability for costs required to clean up and restore sites where substances and wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment.

There is inherent risk of environmental costs and liabilities in our business as a result of our handling of natural gas, NGLs and other hydrocarbons, because of air emissions and waste water discharges related to our operations, and due to historical industry operations, and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup, restoration costs and natural resource damages, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Moreover, it is possible that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may be unable to recover some or any of these costs from insurance.

Risks Related to Our Structure

Our limited liability company agreement prohibits a unitholder who acquires 15% or more of our common units without the approval of our Board of Directors from engaging in a business combination with us for three years. This provision could discourage a change of control that our unitholders may favor, which could negatively affect the price of our common units.

Our limited liability company agreement effectively adopts Section 203 of the Delaware General Corporation Law. Section 203 as it applies to us prevents an interested unitholder, defined as a person who owns 15% or more of our outstanding units, from engaging in business combinations with us for three years following the time such person becomes an interested unitholder, except in limited circumstances. Section 203 broadly defines “business combination” to encompass a wide variety of transactions with or caused by an interested unitholder, including mergers, asset sales and other transactions in which the interested unitholder receives a benefit on other than a pro rata basis with other unitholders. This provision of our limited liability company agreement could have an anti-takeover effect with respect to transactions not approved in advance by our Board of Directors, including discouraging takeover attempts that might result in a premium over the market price for our common units.

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

Our limited liability company agreement does not limit the number of additional limited liability company interests, including common units and other equity securities that rank senior to common units, that we may issue at any time without the approval of our unitholders, and existing NASDAQ listing rules allow us to issue additional interests without unitholder approval so long as we do not exceed 20% of our common units then outstanding. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

 

   

your proportionate ownership interest in us will decrease;

 

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

 

   

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

 

   

the market price of our common units may decline.

Our preferred units, which generally become convertible into common units beginning in July 2013, are entitled to in-kind payments of quarterly distributions for each quarter through the third quarter of 2013. We may elect to continue to pay preferred distributions in kind for each quarter through the third quarter of 2016. All preferred units that we issue in payment of quarterly preferred units in kind will be convertible into common units on a one-for-one basis.

Certain of our investors may sell units in the public market, which could reduce the market price of our outstanding common units.

We have agreed to file a registration statement on Form S-3 to cover sales by TPG Copenhagen, L.P. (“TPG”), an affiliate of TPG Capital, L.P. of all common units issuable upon conversion of our outstanding preferred units and additional preferred units that we issue as in-kind quarterly distributions. If TPG or a successor to its registration rights, or any holder of a significant percentage of our common units, were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price for our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our limited liability company agreement provides for a limited call right that may require you to sell your common units at an undesirable time or price.

If, at any time, any person owns more than 90% of our common units then outstanding, such person has the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the remaining common units then outstanding at a price not less than the then-current market price of our common units. As a result, you may be required to sell your common units at an undesirable time or price and may therefore not receive any return on your investment. You may also incur tax liability upon a sale of your units.

Increases in interest rates could adversely affect our unit price.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. An increase in interest rates could also cause a corresponding decline in demand for equity investments, in general, and in particular for yield-based equity investments such as our common units. Lower demand for our common units for any reason, including competition from other more attractive investment opportunities, would likely cause the trading price of our common units to decline. If we then issue additional equity at a significantly lower price, material dilution to our existing unitholders could result.

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to this or any other tax matter.

 

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Despite the fact that we are a limited liability company under Delaware law, it is possible in certain circumstances for a publicly traded limited liability company such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we should be so treated, 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.

In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject limited liability companies to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, we are required to pay Texas franchise tax at a maximum effective rate of 0.7% of our federal gross income apportioned to Texas in the prior year. Imposition of such a tax on us by any other state will further reduce the cash available for distribution to our unitholders. Moreover, federal legislation that would eliminate pass-through tax treatment for certain publicly traded limited liability companies is proposed from time to time. We cannot predict whether any of these changes or other proposals will ultimately be enacted. Additionally, any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

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 rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gain, loss or deduction would flow through to you. Because a tax would be imposed on us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders and would likely result in a substantial reduction in the value of our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted, and the costs of any IRS contest will reduce cash available for distribution to our unitholders.

We have not requested a 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 take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may disagree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

You will be required to pay taxes on the share of our income allocated to you even if you do not receive any cash distributions from us.

Because our unitholders are treated as partners to whom we allocate taxable income, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, regardless of the amount of any distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell, will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be

 

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taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax-exempt entities and non-U.S. 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, including employee benefit plans and individual retirement accounts (IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to such a unitholder. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted depreciation and amortization positions that may not conform with all aspects of existing Treasury Regulations. 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 on the sale of common units and could have a negative impact on the value of our common units or result in audits of and adjustments to our unitholders’ tax returns.

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. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration 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.

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

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those 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 units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those 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 and lending their units.

 

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

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. While we would continue our existence as a Delaware limited liability company, our technical termination would, among other things result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one fiscal year (and unitholders receiving two schedules K-1) and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination would not affect our classification as a partnership for federal income tax purposes; rather, we would be treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax year in which the termination occurred.

As a result of investing in our common units, you may be subject to state and local taxes and return filing requirements in states where you do not live.

In addition to federal income taxes, unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not reside in any of those jurisdictions. Our 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 jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business and own assets in several states, most of which currently impose a personal income tax. As we make acquisitions or expand our business, we may conduct business or own assets in other jurisdictions that impose a personal income tax. It is the responsibility of each unitholder to file all of the unitholder’s required U.S. federal, state and local tax returns.

 

Item 1B. Unresolved Staff Comments

None.

 

Item 2. Properties

A description of our properties is provided in Item 1 of this report. Substantially all of our pipelines are constructed under rights-of-way granted by the apparent record landowners. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. 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, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipelines were built was purchased in fee.

Some of our leases, easements, rights-of-way, permits, licenses and franchise ordinances require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects. With respect to any consents, permits or authorizations that have not been obtained, we believe that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

 

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We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with their use in the operation of our business.

 

Item 3. Legal Proceedings

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings, except for proceedings described below. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, that would have a significant adverse effect on our financial position or results of operations.

As a result of our Cantera acquisition in October 2007, we acquired Cantera Gas Company LLC (“Cantera Gas Company,” formerly CMS Field Services, Inc. (“CMSFS”)). Cantera Gas Company is a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMSFS and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred before Cantera Resources, Inc. acquired CMSFS in June 2003 (the “CMS Acquisition”). The amount of liability, if any, against Cantera Gas Company is not reasonably estimable. Pursuant to the CMS Acquisition purchase agreement, CMS Gas Transmission has assumed responsibility for the defense of these claims, and Cantera Gas Company is fully indemnified by CMS Gas Transmission and its parent, CMS Enterprises Company, against any losses that Cantera Gas Company may suffer as a result of these claims.

 

Item 4. Mine Safety Disclosures

Not Applicable.

 

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PART II

 

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Common Units

Our common units, which represent limited liability company interests in us, are listed on The NASDAQ Global Select Market (“NASDAQ”), under the symbol “CPNO.” On February 17, 2012, the closing market price for our common units was $36.47 per unit, and there were approximately 99 common unitholders of record.

The following table shows the high and low sales prices per common unit, as reported by NASDAQ, and the distribution per common unit for the periods indicated.

 

            Cash
Distribution
Per Common

Unit
 
     Price of Common Units     
           High                  Low           

2011:

        

Quarter Ended December 31

   $ 34.28       $ 26.08       $ 0.575   

Quarter Ended September 30

   $ 35.39       $ 27.07       $ 0.575   

Quarter Ended June 30

   $ 37.40       $ 31.17       $ 0.575   

Quarter Ended March 31

   $ 36.40       $ 30.23       $ 0.575   

2010:

        

Quarter Ended December 31

   $ 33.77       $ 27.30       $ 0.575   

Quarter Ended September 30

   $ 29.43       $ 24.49       $ 0.575   

Quarter Ended June 30

   $ 27.89       $ 21.53       $ 0.575   

Quarter Ended March 31

   $ 25.62       $ 20.70       $ 0.575   

We intend to pay quarterly distributions to our common unitholders of record on the applicable record date within 45 days after the end of each quarter (in February, May, August and November of each year). Our limited liability company agreement provides that we may pay cash distributions only if and to the extent we have available cash from operating surplus, as defined in the agreement. Available cash consists generally of all cash on hand at the end of the fiscal quarter, less retained cash reserves established by our Board of Directors. Our credit agreement does not provide for the type of working capital borrowings that would be eligible for inclusion in available cash.

Our Board of Directors has broad discretion to establish cash reserves that it determines are necessary or appropriate for the proper conduct of our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize quarterly cash distributions, reserves to reduce debt or, as necessary, reserves to comply with the law or with the terms of any of our agreements or obligations.

Our ability to distribute cash is subject to a number of risks and uncertainties, some of which are beyond our control. Please read Item 1A, “Risk Factors—Risks Relating to Our Business.” If we do not have sufficient cash to pay a distribution as well as satisfy our operational and financial obligations, then our Board of Directors can reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments. For a discussion of the restrictions on distributions imposed by our revolving credit facility and the indentures governing our senior unsecured notes, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

Securities Authorized for Issuance under Equity Compensation Plans

Information concerning securities authorized for issuance under our equity compensation plan for directors and employees is incorporated herein by reference to our Proxy Statement for our 2012 Annual Meeting of Unitholders set forth under the caption “Securities Authorized for Issuance under Equity Compensation Plans.”

 

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Series A Convertible Preferred Units

On July 21, 2010, we issued 10,327,022 Series A convertible preferred units (“preferred units”) in a private placement to an affiliate of TPG Capital, L.P for gross proceeds of $300 million. The preferred units were priced at $29.05 per unit, a 10% premium to the 30-day volume-weighted average closing price of our common units on July 19, 2010, two trading days before the date we issued the preferred units. The preferred units were sold pursuant to a purchase agreement in a transaction exempt from registration under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), and the rules and regulations promulgated there under, as the issuance and sale of the preferred units did not involve a public offering. There is no established public trading market for the preferred units. For a description of the terms of our preferred units, please read “Member’s Capital and Distributions—Series A Convertible Preferred Units” in Note 6 to our consolidated financial statements included in Item 8 of this report.

Common Unitholder Return Performance Presentation

The performance graph below compares the cumulative total unitholder return on our common units with the cumulative total returns on the Standard & Poor’s 500 Index (the “S&P 500 Index”) and the Alerian MLP Total Return Index (the “Alerian Total Return Index”). The Alerian Total Return Index is a composite of the 50 most prominent energy master limited partnerships and limited liability companies, as determined by Standard & Poor’s using a float-adjusted market capitalization methodology. The graph assumes an investment of $100 in our common units, and in each of the S&P 500 Index and the Alerian Total Return Index on January 1, 2007, and reinvestment of all dividends and distributions. The results shown in the graph are based on historical data and should not be considered indicative of future performance.

 

LOGO

 

     January  1,
2007
     December 31,  
        2007      2008      2009      2010      2011  

Copano (CPNO)

   $ 100       $ 128       $ 44       $ 102       $ 154       $ 164   

Alerian MLP Total Return Index (AMZX)

   $ 100       $ 113       $ 71       $ 125       $ 170       $ 194   

S&P 500 Index (SPX)

   $ 100       $ 104       $ 64       $ 79       $ 89       $ 89   

 

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Notwithstanding anything to the contrary set forth in any of our previous or future filings under the Securities Act or the Exchange Act that might incorporate this report or future filings with the SEC, in whole or in part, the preceding performance information shall not be deemed to be “soliciting material” or to be “filed” with the SEC or incorporated by reference into any filing except to the extent this performance presentation is specifically incorporated by reference therein.

Issuer Purchases of Equity Securities

None.

Recent Sales of Unregistered Securities

Not applicable.

 

Item 6. Selected Financial Data

Selected Historical Consolidated Financial Information

The following table shows our selected historical consolidated financial information for the periods and as of the dates indicated. This information is derived from, should be read together with and is qualified in its entirety by reference to, our historical audited consolidated financial statements and the accompanying notes included in Item 8 of this report. The selected financial information should also be read together with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

 

     Year Ended December 31,  
     2011     2010     2009      2008      2007(1)  
     (In thousands, except per unit data)  

Summary of Operating Results:

            

Revenue(2)

   $ 1,345,223      $ 995,164      $ 820,046       $ 1,454,419       $ 1,064,515   

(Loss) income from continuing
operations

   $ (156,312   $ (8,681   $ 20,866       $ 55,922       $ 61,381   

Preferred unit distributions

   $ (32,721   $ (15,188   $ —         $ —         $ —     

Net (loss) income to common units

   $ (189,033   $ (23,869   $ 20,866       $ 55,922       $ 61,381   

Basic (loss) income per common unit from continuing operations(3)

   $ (2.86   $ (0.37   $ 0.39       $ 1.15       $ 1.44   

Diluted (loss) income per common unit from continuing operations(3)

   $ (2.86   $ (0.37   $ 0.36       $ 0.97       $ 1.32   

Other Financial Information:

            

Cash distributions declared per common unit

   $ 2.30      $ 2.30      $ 2.30       $ 2.17       $ 1.73   
     December 31,  
     2011     2010     2009      2008      2007(1)  
     (In thousands)  

Balance Sheet Information:

            

Total assets

   $ 2,064,597      $ 1,906,993      $ 1,867,412       $ 2,013,665       $ 1,769,083   

Long-term debt

   $ 994,525      $ 592,736      $ 852,818       $ 821,119       $ 630,773   

Members’ capital

   $ 871,898      $ 1,154,757      $ 860,026       $ 1,037,958       $ 894,136   

 

(1) Our selected financial information as of and for the year ended December 31, 2007 includes results attributable to our Cimmarron acquisition from May 1, 2007 through December 31, 2007 and our Rocky Mountains segment from October 1, 2007 (the date we acquired Cantera) through December 31, 2007.

 

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(2) Our selected financial data as of and for the years ended December 31, 2009, 2008 and 2007 excludes the results attributable to our crude oil pipeline and related activities, as they are classified as discontinued operations. Please read Note 13, “Discontinued Operations,” to the audited consolidated financial statements included in Item 8 of this report.
(3) Net income per unit is based on the weighted average of total equivalent units outstanding during the periods presented. Prior periods have been adjusted to reflect the two-for-one split of our outstanding common units effective March 30, 2007.

 

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the historical consolidated financial statements and notes thereto included in Item 8 of this report. In addition, you should review “—Forward-Looking Statements” included in this Item 7 and “Risk Factors” included in Item 1A of this report for information regarding forward-looking statements made in this discussion and certain risks inherent in our business, as well as Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”

Overview

Through our subsidiaries and equity investments, we own and operate natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. We operate in Texas, Oklahoma, Wyoming and Louisiana. We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Texas, Oklahoma and Rocky Mountains.

 

   

Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation. This segment includes a processing plant located in southwest Louisiana and our equity investments in Webb Duval, Eagle Ford Gathering, Liberty Pipeline Group and Double Eagle Pipeline.

 

   

Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome.

 

   

Our Rocky Mountains segment provides natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas and compressor rental services. This segment includes our equity investments in Bighorn and Fort Union.

Items reported as “Corporate and other” relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with “—How We Evaluate Our Operations” and “—How We Manage Our Operations” below. Many of the factors affecting our business are beyond our control and are difficult to predict.

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are affected by natural gas and NGL prices and by our natural gas and NGL volumes, which are a function primarily of drilling activity near our gathering and processing assets. Generally, natural gas and NGL prices affect the cash flow and profitability of our Texas and Oklahoma segments directly because some of our contracts in those segments have commodity-sensitive pricing terms. In addition, natural gas and NGL prices, and to a lesser degree, crude oil prices, also affect all of our segments indirectly because they influence exploration and production activity, which underlie the demand for our services and the long-term growth and sustainability of our business.

Commodity prices generally are influenced by various factors that affect supply and demand. These factors include regional drilling activity, storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and the availability and proximity of pipeline and NGL-handling capacity and markets for natural gas and NGLs. Many of the factors affecting demand are in turn dependent on overall economic activity.

 

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For example, demand for ethane, a primary feedstock for petrochemical and manufacturing industries, varies depending on overall economic activity. Factors that can cause volatility in crude oil prices, such as international political and economic events, can also affect NGL prices because the two tend to be highly correlated.

Producers typically increase drilling and well completions when prices are sufficient to make these activities economic and, depending on the severity and duration of an unfavorable pricing environment, may suspend these activities to the degree they have become uneconomic. Changes in drilling and completion activity are reflected in production volumes (and in turn, in our throughput volumes) only gradually because of the time required to drill, complete and attach new wells (or if drilling is declining, because of continuing production from existing wells). Delays between the time wells are drilled and actual flow to market can range from a few days in areas with minimal completion and attachment processes to as long as 18 months for extensive dewatering or completion of facilities involving long lead times. In addition, delays between drilling and flow can be dependent on downstream factors such as availability of liquids removal, transportation capabilities and market demand.

The point at which producer activity becomes economic depends on a combination of factors in addition to commodity prices. For producers of rich gas who benefit from improved processing economics under their contracts, the potential disincentive of low natural gas prices could be offset if NGL prices are consistently high. Strong crude oil prices could also support increased production of casinghead natural gas associated with crude oil production.

Other factors that affect a producer’s ability and incentives to drill include the availability of capital and the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir and the availability of equipment and services, among other things. The expected composition of wellhead production and the availability and proximity of transportation, processing and fractionation infrastructure and market outlets are significant considerations. A factor that we believe has supported strong activity in unconventional shale plays is low geologic risk—that is, a greater likelihood that wells drilled will be productive—which reduces a producer’s overall development risk and ultimately drilling costs. Also, some producers rely on commodity price hedging to support drilling activity when prices are less favorable, and some may drill only to the extent that drilling activity is necessary to maintain their leasehold interests or under the terms of their capital commitments.

Fourth-Quarter Commodity Prices Overall. Natural gas prices overall averaged below $4 per MMBtu for the fourth quarter of 2011, crude oil prices increased steadily and average NGL prices remained flat throughout the quarter.

Pricing Trends in Texas. Natural gas and NGL prices in Texas decreased in the fourth quarter of 2011. Through February 17, 2012, NGL and natural gas prices decreased as compared to the fourth quarter of 2011. First-of-the-month prices for natural gas on the Houston Ship Channel index were $3.04 per MMBtu for January 2012 and $2.57 per MMBtu for February 2012, and the spot price at February 17, 2012 was $2.47 per MMBtu. The weighted-average daily price for NGLs at Mont Belvieu as of February 17, 2012, based on our fourth quarter weighted-average 2011 product mix, was $49.51 per Bbl.

 

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The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Texas pricing and for crude oil on the NYMEX.

 

LOGO

 

(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on Mont Belvieu prices and our weighted-average product mix for the period indicated.

 

    Annual Data for Texas          Quarterly Data for Texas  
    2009     2010     2011          Q1 2011     Q2 2011     Q3 2011     Q4 2011  

Houston Ship Channel
($/MMBtu)

  $ 3.78      $ 4.38      $ 4.02          $ 4.06      $ 4.29      $ 4.23      $ 3.49   

Mont Belvieu ($/Bbl)

  $ 33.51      $ 44.68      $ 56.96          $ 51.22      $ 58.57      $ 59.43      $ 57.76   

NYMEX crude oil ($/Bbl)

  $ 62.09      $ 79.53      $ 95.12          $ 94.10      $ 102.56      $ 89.76      $ 94.06   

Service throughput (MMBtu/d)

    619,615        595,641        795,497            654,996        665,040        765,744        844,469   

Plant inlet (MMBtu/d)

    539,633        504,810        758,588            560,903        588,533        686,398        803,282   

NGLs produced (Bbls/d)

    17,959        18,718        29,147            23,228        26,913        30,904        33,951   

Segment gross margin (in thousands)(1)

  $ 103,620      $ 128,682      $ 184,437          $ 45,011      $ 46,134      $ 44,540      $ 48,752   

 

(1) Excludes results associated with our equity interests in Eagle Ford Gathering, Webb Duval, Liberty Pipeline group, Double Eagle Pipeline.

Pricing Trends in Oklahoma. NGL and natural gas prices in Oklahoma declined in the fourth quarter of 2011. Through February 17, 2012, NGL and natural gas prices decreased. First-of-the-month prices for natural gas on the CenterPoint East index were $2.97 per MMBtu for January 2012 and $2.53 per MMBtu for February 2012, and the spot price at February 17, 2012 was $2.41 per MMBtu. The weighted-average daily price for NGLs at Conway as of February 17, 2012, based on our fourth quarter 2011 weighted-average product mix, was $38.93 per Bbl.

 

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The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Oklahoma pricing and for crude oil on the NYMEX.

 

LOGO

 

(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on Conway prices and our weighted-average product mix the period indicated.

 

     Annual Data for Oklahoma          Quarterly Data for Oklahoma  
     2009     2010     2011          Q1 2011     Q2 2011     Q3 2011     Q4 2011  

CenterPoint East ($/MMBtu)

  $ 3.27      $ 4.19      $ 3.87          $ 3.93      $ 4.14      $ 4.05      $ 3.38   

Conway ($/Bbl)

  $ 29.65      $ 40.21      $ 47.32          $ 46.36      $ 50.17      $ 49.21      $ 43.49   

NYMEX crude oil ($/Bbl)

  $ 62.09      $ 79.53      $ 95.12          $ 94.10      $ 102.56      $ 89.76      $ 94.06   

Service throughput (MMBtu/d)

    262,259        261,636        291,532            269,550        283,870        288,440        307,346   

Plant inlet (MMBtu/d)

    163,474        156,181        160,406            147,710        157,424        158,070        159,344   

NGLs produced (Bbls/d)

    15,977        16,251        17,498            16,037        17,331        17,453        17,471   

Segment gross margin (in thousands)(1)

  $ 76,686      $ 93,617      $ 105,080          $ 23,082      $ 28,665      $ 27,876      $ 25,457   

 

(1) Excludes results associated with our equity interest in Southern Dome.

Basis Trends. The average basis differential between Conway and Mont Belvieu continued to widen for the fourth quarter of 2011 consistent with the third quarter 2011, ending the year at $13.99 per Bbl. Prices for purity ethane accounted for 63% of this basis differential. For January 2012, the basis differential averaged $12.93 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.11 per MMBtu for the fourth quarter of 2011, which was an increase of $0.07 per MMBtu as compared with the third quarter. The basis differential was $0.07 MMBtu for January 2012 and $0.01 per MMBtu at February 17, 2012.

 

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The following graph summarizes the basis differential between Mont Belvieu and Conway.

 

LOGO

 

(1) Average NGL prices are calculated based on our Oklahoma segment weighted-average product mix for the period indicated.

Pricing Trends in the Rocky Mountains. Rocky Mountains natural gas prices declined during the fourth quarter of 2011. Through February 17, 2012, natural gas prices have continued to decline. First-of-the-month prices for natural gas on the Colorado Interstate Gas index were $2.98 per MMBtu for January 2012 and $2.51 per MMBtu for February 2012, and the spot price at February 17, 2012 was $2.40 per MMBtu.

The following graph and table summarize prices for natural gas on Colorado Interstate Gas, the primary index we use for the Rocky Mountains.

 

LOGO

 

(1) Natural gas prices are first-of–the-month index prices.

 

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     Annual Data for Rocky Mountains          Quarterly Data for Rocky Mountains  
     2009     2010     2011          Q1 2011     Q2 2011     Q3 2011     Q4 2011  

Colorado Interstate Gas ($/MMBtu)

  $ 3.07      $ 3.92      $ 3.79          $ 3.83      $ 3.98      $ 3.91      $ 3.43   

Pipeline throughput (MMBtu/d)(1)

    975,785        907,809        604,261            581,051        533,329        670,543 (3)      630,843 (3) 

Segment gross margin (in thousands)(2)

  $ 3,254      $ 4,440      $ 2,641          $ 1,042      $ 771      $ 432      $ 396   

 

(1)

Includes 100% of Bighorn and Fort Union, but does not reflect an additional 288,966 MMBtu/d, 327,894 MMBtu/d, 223,557 MMBtu/d and 232,693 MMBtu/d of long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union in the first, second, third and fourth quarters of 2011, respectively.

(2)

Excludes results associated with our equity interests in Bighorn and Fort Union.

(3)

Fort Union volumes increased during the third and fourth quarters of 2011 following a temporary force majeure event on TransCanada’s Bison pipeline and subsequent deliveries of producer volumes into Fort Union from Bison.

Fourth Quarter 2011 Drilling and Production Activity.

 

   

Drilling. Drilling activity in the fourth quarter of 2011 remained very strong in the Eagle Ford Shale in Texas, where we continued to work to secure additional long-term supply contracts. Producer activity in the Woodford Shale behind our Mountains systems in Oklahoma and the north Barnett Shale Combo play behind our Saint Jo plant in Texas was consistent with the first three quarters of 2011. Drilling activity in the Mississippi Lime area in northern Oklahoma and southern Kansas has increased as producers further explore the play. In the Rocky Mountains and in other areas of Texas and Oklahoma, drilling activity has remained low.

 

   

Volumes. Our overall service throughput volumes for the fourth quarter of 2011 increased 7% compared to the third quarter of 2011. In Texas, volume increases reflected a 94% increase in Eagle Ford Shale volumes (including volumes from Eagle Ford Gathering that began flowing on a limited basis to our Houston Central complex in August 2011), a 19% increase in volumes on our Saint Jo system and volumes processed at our Lake Charles plant, which we restarted in November 2011. The increase in Texas volumes was offset in part by a 22% decrease in third-party pipeline volumes we received from Kinder Morgan at our Houston Central complex and decreases on our other systems due to natural production declines around these systems.

Volumes in Oklahoma increased 7% from third quarter volumes as a result of a 21% increase in Mountain systems volumes. This increase was partially offset by natural production decline on the other Oklahoma gathering systems we operate. In the Rocky Mountains, Fort Union volumes declined 7% following the resolution of a third-quarter force majeure event on TransCanada’s Bison Pipeline, during which a portion of Bison’s volumes were diverted to Fort Union. Volumes on Bighorn remained flat over the period.

 

   

Outlook. So long as NGL and crude prices generally remain strong relative to natural gas prices, we anticipate continued drilling activity in rich gas areas such as the Eagle Ford Shale and the north Barnett Shale Combo plays. We believe that these plays are attractive to producers because they offer rich gas in a favorable NGL price environment, low geologic risk and nearby infrastructure and market access, as well as high initial production rates. In addition, we have seen moderate increases in drilling activity in the Mississippi Lime play in northern Oklahoma and continue to evaluate opportunities to expand into the play from our existing assets in the area.

Natural gas prices have been relatively stable but have not yet reached levels that provide producers incentives to increase drilling in the Powder River Basin and in areas where producers employ conventional drilling techniques. Drilling and related activity in shale plays have consumed significant capital and other resources, which may effectively raise barriers to entry in other areas. However, other

 

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factors such as commodity hedges, improved well completion technology or the need to maintain leasehold interests will also influence drilling and completion activity. We expect that many producers who rely on conventional drilling, produce mainly lean gas, or both, will wait to see sustained increases in natural gas prices before resuming significant drilling activity. We do not expect volume growth in the Rocky Mountains until prices are sufficient to support substantial drilling and completion activity.

Other Industry Trends. NGL transportation and fractionation facilities continue to experience capacity constraints, which generally results in higher NGL transportation and fractionation costs for parties that do not have contractually fixed costs. Growing rich natural gas volumes from the Eagle Ford Shale are placing additional pressure on fractionation capacity and existing transportation capacity for NGLs, condensate and crude oil, while transportation costs for heavier NGL products in Texas remain higher due to limited broad pipeline infrastructure and trucking capacity.

We believe a lack of infrastructure also is among the factors contributing to the recent widening basis spread between Conway and Mont Belvieu. Mont Belvieu prices, particularly for ethane, have been supported by strong demand from the petrochemical market along the Gulf Coast. At the same time, Conway NGL prices have declined as insufficient takeaway capacity has resulted in an oversupply in the region.

We expect that over the next two years, the effects of these capacity constraints will be moderated by new fractionation facilities and NGL transportation infrastructure, including new NGL pipelines linking the Mid-Continent to the Gulf Coast.

In the near term, these effects could limit the benefits producers receive from rich gas production and could affect the level of drilling and well completion activity in some rich gas plays. In addition, activity in the Eagle Ford Shale over the long term could be impacted by insufficient demand and storage capacity for residue gas and NGLs as well as by a shortage of required resources, such as water used in hydraulic fracturing.

Please read Item 1A, “Risk Factors—Risks Related to our Business.”

Factors Affecting Operating Results and Financial Condition

Our results for 2011 reflect increases in NGL prices compared to 2010 as well as volume growth due to strong drilling activity and the start-up of Eagle Ford Gathering’s pipeline. Strong NGL prices in Texas and Oklahoma combined with lower natural gas prices during 2011 have continued to benefit our processing margins. Our combined operating segment gross margins increased 29% compared to 2010. These factors, combined with additional processing margins we received under short-term, interruptible arrangements before our capital projects were in full service, offset the effects of downtime at our Houston Central complex to complete capital projects and curtailments due to downstream liquids-handling constraints. Houston Central NGL volumes were curtailed from September 2011 to November 2011 due to a turnaround at Formosa’s processing facility and a shut-down of our propane line to Dow for scheduled maintenance.

For the third quarter of 2011, we recorded a $120.0 million non-cash impairment charge relating to our investment in Bighorn, a $45.0 million non-cash impairment charge relating to our investment in Fort Union and a $5.0 million non-cash impairment charge relating to a contract under which we provide services to Rocky Mountains producers. We determined that these charges were necessary primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and, as producers focus more on rich-gas and shale plays, a continued lack of drilling activity in Wyoming’s Powder River Basin. For the fourth quarter of 2011, we recorded a $3.4 million non-cash impairment charge relating to assets in south Texas.

Higher NGL and crude oil prices in 2011 combined with lower strike prices on our commodity derivative instruments reduced our cash flow from commodity hedge settlements. Also, a substantial widening of the

 

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Conway-Mont Belvieu basis differential (primarily attributable to ethane prices) limited the effectiveness of our derivative instruments for hedging Oklahoma NGLs by approximately $3.7 million for 2011. In 2011, we paid $10.6 million in net cash settlements for expired commodity derivative instruments compared to receiving $33.6 million in net cash settlements in 2010.

How We Evaluate Our Operations

We believe that investors and other market participants benefit from having access to the various financial and operating measures that our management uses in evaluating our performance. These measures include: (i) throughput volumes; (ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) total distributable cash flow.

Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-generally accepted accounting principles, or non-GAAP, financial measures. We use non-GAAP financial measures to evaluate our core profitability and to assess the financial performance of our assets. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Our non-GAAP financial measures may not be comparable to similarly titled measures of other companies, which may not calculate their measures in the same manner.

Throughput Volumes. Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate the volumes delivered to our processing plants and flowing through our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is also significantly influenced by quality of natural gas delivered to the plant, the NGL content of the natural gas and the plant’s recovery capability. In addition, we monitor fuel consumption and losses because they have a significant impact on the gross margin realized from our processing operations through contractual agreements where we provide a fixed recovery to our producers. Where contractual agreements allow, fuel costs and losses are passed on to our producers.

It is also important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes. In monitoring our pipeline volumes, managers of our Texas and Oklahoma segments evaluate what we refer to as service throughput, which consists of two components:

 

   

the volume of natural gas transported or gathered through our wholly owned pipelines, which we call pipeline throughput; and

 

   

the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines or the volume of natural gas delivered to third-party plants under our transportation or processing contracts, excluding any volumes already included in our pipeline throughput.

In our Texas segment, we also compare pipeline throughput and service throughput to evaluate the volumes generated from our pipelines, as opposed to third-party pipelines. In Oklahoma, because no gas is delivered to our wholly owned plants other than by our pipelines, pipeline throughput and service throughput are equivalent.

Segment Gross Margin and Total Segment Gross Margin. We define segment gross margin as an operating segment’s revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs we

 

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purchase and costs for transportation or processing of our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to more easily identify operational or other issues within a segment. With respect to our Texas and Oklahoma segments, our management analyzes segment gross margin per unit of service throughput.

We use total segment gross margin to measure the overall financial impact of our contract portfolio. Total segment gross margin is the sum of our operating segments’ gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume and quality of natural gas gathered or transported through our pipelines, (ii) the volume and NGL content of natural gas processed, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas, crude oil and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities. The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii) amortization expense relating to the option component of our commodity derivative instruments and (iii) unrealized mark-to-market gain or loss on our commodity derivative instruments that have not been designated as cash flow hedges.

Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for oil, natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon the market demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Both segment gross margin and total segment gross margin are reviewed monthly for consistency and trend analysis.

Joint Venture Distributions. The cash distributions we receive in respect of our joint venture interests are also important to our operational analysis. In addition, we serve each of our joint ventures as managing member, operator, or both. In our role as managing member or operator, we generally use the other financial and operating measures described in this section and below in “—How We Manage Our Operations” to evaluate and monitor the performance of our joint ventures.

Operations and Maintenance Expenses. The most significant portion of our operations and maintenance expenses consists of direct labor, insurance, repair and maintenance, utilities and contract services. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. We monitor operations and maintenance expenses to assess the impact of such costs on the profitability of a particular asset or group of assets and to evaluate the efficiency of our operations.

General and Administrative Expenses. Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. To help ensure the appropriateness of our general and administrative expenses, we compare such expenses against the annual financial plan approved by our Board of Directors.

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation and amortization expense. Commencing with the second quarter of 2011, we revised our calculation of adjusted EBITDA to more closely resemble that of many of our peers in terms of measuring our ability to generate cash. Our adjusted EBITDA (as revised) equals:

 

   

net income (loss);

 

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plus interest and other financing costs, provision for income taxes, depreciation and amortization expense, impairment expense, non-cash amortization expense associated with our commodity derivative instruments, distributions from unconsolidated affiliates, loss on refinancing of unsecured debt and equity-based compensation expense;

 

   

minus equity in earnings (loss) from unconsolidated affiliates and unrealized gains (losses) from commodity risk management activities; and

 

   

plus or minus other miscellaneous non-cash amounts affecting net income (loss) for the period.

In calculating adjusted EBITDA as revised, we no longer add to EBITDA our share of the depreciation, amortization and impairment expense and interest and other financing costs embedded in our equity in earnings (loss) from unconsolidated affiliates; instead, we now add to EBITDA (i) other non-cash amounts affecting net income (loss) for the period, (ii) non-cash amortization expense associated with our commodity derivative instruments, (iii) loss on refinancing of unsecured debt and (iv) distributions from unconsolidated affiliates.

We believe that our revised calculation of adjusted EBITDA is a more effective tool for our management in evaluating our operating performance for several reasons. Although our historical method of calculating adjusted EBITDA was useful in assessing the performance of our assets (including our unconsolidated affiliates) without regard to financing methods, capital structure or historical cost basis, the prior calculation was not as useful in evaluating the core performance of our assets and their ability to generate cash because adjustments for a number of non-cash expenses and other non-cash and non-operating items were not reflected in the calculation, and the impact of cash distributions from our unconsolidated affiliates was likewise not reflected. We believe that the revised calculation of adjusted EBITDA is more consistent with the method and presentation used by many of our peers and will allow management and analysts to better evaluate our performance relative to our peer companies.

External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or adjusted EBITDA, and our management uses adjusted EBITDA, as a supplemental financial measure to assess:

 

   

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

 

   

the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

 

   

our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

 

   

the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

We believe that the revised calculation more effectively represents what lenders and debt holders, as well as industry analysts and many of our unitholders, have indicated is useful in assessing our core performance and outlook and comparing us to other companies in our industry. For example, we believe that adjusted EBITDA as revised may provide investors and analysts with a more useful tool for evaluating our leverage because it more closely resembles Consolidated EBITDA (as defined under our revolving credit facility), which is used by our lenders to calculate our financial covenants. Consolidated EBITDA differs from adjusted EBITDA in that it includes further adjustments to (i) reflect the pro forma effects of material acquisitions and dispositions and (ii) in the case of leverage ratio calculations, includes projected EBITDA from significant capital projects under construction. Please read—Liquidity and Capital Resources—Our Indebtedness—Revolving Credit Agreement.

Total Distributable Cash Flow. Commencing with the second quarter of 2011, we present total distributable cash flow as net income (loss) plus all adjustments included in the adjusted EBITDA calculation described above and minus: (i) cash interest expense, (ii) current tax expense and (iii) maintenance capital expenditures. Although

 

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we have revised our presentation of total distributable cash flow, the components of the calculation have not changed except that total distributable cash flow now eliminates the impact of any loss on refinancing of unsecured debt because such losses do not reduce operating cash flow.

Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows we generate (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders. Using total distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

Total distributable cash flow is also an important non-GAAP financial measure for our unitholders because it serves as an indicator of our success in providing a cash return on investment—specifically, whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Total distributable cash flow is also used by industry analysts with respect to publicly-traded partnerships and limited liability companies because the market value of such entities’ equity securities is significantly influenced by the amount of cash they can distribute to unitholders. Because of the significance of total distributable cash flow to our unitholders, our Compensation Committee and Board of Directors have designated total distributable cash flow per common unit as the financial objective under our Management Incentive Compensation Plan since the plan’s inception in 2005.

 

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Reconciliation of Non-GAAP Financial Measures. The following table presents a reconciliation of the non-GAAP financial measures of (i) total segment gross margin to the GAAP financial measure of operating income and (ii) EBITDA, adjusted EBITDA and total distributable cash flow to the GAAP financial measure of net income (loss), for each of the periods indicated. The reconciliation of the non-GAAP financial measures for 2010 and 2009 have been recast to conform with the revised calculation to allow for direct comparisons to 2011 activity.

 

     Year Ended December 31,  
     2011     2010     2009  
     (In thousands)  

Reconciliation of total segment gross margin to operating income:

      

Operating (loss) income

   $ (89,450   $ 45,777      $ 72,355   

Add: Operations and maintenance expenses

     65,326        53,487        51,477   

Depreciation, amortization and impairment 

     77,565        62,572        56,975   

General and administrative expenses

     48,680        40,347        39,511   

Taxes other than income

     5,130        4,726        3,732   

Equity in loss (earnings) from unconsolidated affiliates

     145,324        20,480        (4,600
  

 

 

   

 

 

   

 

 

 

Total segment gross margin

   $ 252,575      $ 227,389      $ 219,450   
  

 

 

   

 

 

   

 

 

 

Reconciliation of EBITDA, adjusted EBITDA and total distributable cash flow to net (loss) income:

      

Net (loss) income

   $ (156,312   $ (8,681   $ 23,158   

Add: Depreciation and amortization

     69,156        62,572        57,539   

Interest and other financing costs

     47,187        53,605        55,836   

Provision for income taxes

     1,502        931        794   
  

 

 

   

 

 

   

 

 

 

EBITDA

     (38,467     108,427        137,327   

Add: Amortization of commodity derivative options

     29,517        32,378        36,950   

Distributions from unconsolidated affiliates 

     35,471        25,955        29,684   

Loss on refinancing of unsecured debt

     18,233        —          —     

Equity-based compensation

     13,265        10,388        8,252   

Equity in loss (earnings) from unconsolidated affiliates

     145,324        20,480        (4,600

Unrealized (gain) loss from commodity risk management activities

     (550     582        (4,131

Impairment

     8,409        —          —     

Other non-cash operating items

     118        1,319        (2,387
  

 

 

   

 

 

   

 

 

 

Adjusted EBITDA

     211,320        199,529        201,095   

Less: Cash interest and other financing costs

     (46,395     (51,417     (54,629

Provision for income taxes and other

     (1,207     (991     (282

Maintenance capital expenditures

     (13,490     (9,563     (9,728
  

 

 

   

 

 

   

 

 

 

Total distributable cash flow(1)

   $ 150,228      $ 137,558      $ 136,456   
  

 

 

   

 

 

   

 

 

 

 

(1) Prior to any retained cash reserves established by our Board of Directors.

How We Manage Our Operations

Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models, (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting, (iv) imbalance monitoring and control and (v) measurement and loss reports.

Economic Models. We use our economic models to determine (i) whether we should reduce the ethane extracted from natural gas processed by some of our processing plants and third-party plants and (ii) whether we should reduce the rate of recovery of other products at our processing plants.

 

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Our recent Eagle Ford Shale expansion projects and our increasingly fee-based contract portfolio have changed how we manage operations at our Houston Central complex. In the past, our commodity price risk was largely related to “keep-whole” pricing, which meant that our margins depended on the spread between natural gas and NGL prices. To mitigate the risk of negative processing margins, which occur when NGL prices fall to near or below natural gas prices, we could “condition,” rather than process, natural gas by extracting only the volume of NGLs necessary to meet downstream pipeline specifications. We calculated what we referred to as a “standardized processing margin” to monitor the impact of natural gas and NGL prices on our Houston Central complex operations and to help determine when we would benefit from conditioning.

Because of recent changes in our assets and our business, natural gas conditioning at the Houston Central complex has become less important from a commodity-risk management standpoint and less effective from an operational standpoint. The pricing terms of producer contracts supporting our Saint Jo processing operations in north Texas and our Eagle Ford Shale expansion projects in south Texas are predominantly fee-based, which has substantially reduced the potential impact that negative processing margins could have on our Texas operations. In addition, as Eagle Ford Shale volumes have increased, the NGL content of natural gas delivered to the Houston Central complex has increased. If we were to condition this very rich natural gas, we would be unable to meet downstream pipeline specifications.

Please read Item 1, “Business—Industry Overview—Midstream Contracts” and Item 7A, “Quantitative and Qualitative Disclosures about Market Risk” for more information about commodity price sensitivity under our contracts.

Flow and Transaction Monitoring Systems. We use automated systems that track commercial activity on and monitor the flow of natural gas on our pipelines in each of our segments. We track each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our pipeline assets. Additionally, we use automated Supervisory Control and Data Acquisition (“SCADA”) systems, which assist management in monitoring and operating our Texas segment. These SCADA systems allow us to monitor our assets at remote locations and respond to changes in pipeline operating conditions. For our Oklahoma segment, we electronically monitor pipeline volumes and operating conditions at certain key points along our pipeline systems and use a SCADA system on some of our gathering systems. Bighorn, which our Rocky Mountains segment operates, also uses a SCADA system.

Producer Activity Evaluation and Reporting. We monitor producer drilling and completion activity in our areas of operation to identify anticipated changes in production and potential new well connection opportunities. The continued connection of natural gas production to our pipeline systems is critical to our business and directly impacts our financial performance. Using a third-party electronic reporting system, we receive daily reports of new drilling permits and completion reports filed with the state regulatory agency that governs these activities in Texas and Oklahoma. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel. These processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines. In all our operating segments, we meet with producers to better understand their drilling and production plans, and to obtain drilling schedules, if available, to assist us in anticipating future activity on our pipelines.

Imbalance Monitoring and Control. We continually monitor volumes received and volumes delivered on behalf of third parties to ensure we remain within acceptable imbalance limits during the calendar month. We seek to reduce imbalances because of the inherent commodity price risk that results when receipts and deliveries of natural gas are not balanced concurrently. We have implemented “cash-out” provisions in many of our transportation and gathering agreements to reduce this commodity price risk. Cash-out provisions require that any imbalance that exists between a third party and us at the end of a calendar month is settled in cash based upon a pre-determined pricing formula. These provisions ensure that imbalances under such contracts are not carried forward from month-to-month and revalued at higher or lower prices.

Measurement and Loss Reports. We use measurement, fuel and loss reports to monitor the efficiency and integrity of our systems.

 

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Forward-Looking Statements

This report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements other than statements of historical fact included in this report, including, but not limited to, those under “—Our Results of Operations” and “—Liquidity and Capital Resources” are forward-looking statements. Statements included in this report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include assertions related to plans for growth of our business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in these statements. Any differences could be caused by a number of factors, including, but not limited to:

 

   

the volatility of prices and market demand for natural gas, crude oil and NGLs, and for products derived from these commodities;

 

   

our ability to continue to connect new sources of natural gas and condensate and the NGL content of new gas supplies;

 

   

the ability of key producers to continue to drill and successfully complete and attach new natural gas and NGL and condensate volumes;

 

   

our ability to attract and retain key customers and contract with new customers;

 

   

our ability to access or construct new gas processing, NGL fractionation and transportation capacity;

 

   

the availability of local, intrastate and interstate transportation systems and other facilities and services for natural gas and NGLs;

 

   

our ability to meet in-service dates, cost expectations and performance standards for construction projects;

 

   

our ability to successfully integrate any acquired asset or operations;

 

   

our ability to access our revolving credit facility and to obtain additional financing on acceptable terms;

 

   

the effectiveness of our hedging program;

 

   

general economic conditions;

 

   

force majeure situations such as the loss of a market or facility downtime;

 

   

the effects of government regulations and policies; and

 

   

other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, including in conjunction with the forward-looking statements referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth under Item 1A, “Risk Factors.” All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. Forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

 

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Our Results of Operations

 

     Year Ended December 31,  
     2011     2010     2009  
     ($ In thousands)  

Total segment gross margin(1)(2)

   $ 252,575      $ 227,389      $ 219,450   

Operations and maintenance expenses(2)

     65,326        53,487        51,477   

Depreciation, amortization and impairment(2)

     77,565        62,572        56,975   

General and administrative expenses

     48,680        40,347        39,511   

Taxes other than income

     5,130        4,726        3,732   

Equity in loss (earnings) from unconsolidated affiliates(3)(4)

     145,324        20,480        (4,600
  

 

 

   

 

 

   

 

 

 

Operating (loss) income(2)(3)

     (89,450     45,777        72,355   

Loss on refinancing of unsecured debt

     (18,233     —          3,939   

Interest and other financing costs, net

     (47,127     (53,527     (54,634

Provision for income taxes

     (1,502     (931     (794

Discontinued operations, net of tax

     —          —          2,292   
  

 

 

   

 

 

   

 

 

 

Net (loss) income

     (156,312     (8,681     23,158   

Preferred unit distributions

     (32,721     (15,188     —     
  

 

 

   

 

 

   

 

 

 

Net (loss) income to common units

   $ (189,033   $ (23,869   $ 23,158   
  

 

 

   

 

 

   

 

 

 

Total segment gross margin:

      

Texas

   $ 184,437      $ 128,682      $ 103,620   

Oklahoma(2)

     105,080        93,617        76,686   

Rocky Mountains(5)

     2,641        4,440        3,254   
  

 

 

   

 

 

   

 

 

 

Segment gross margin(2)

     292,158        226,739        183,560   

Corporate and other(6)

     (39,583     650        35,890   
  

 

 

   

 

 

   

 

 

 

Total segment gross margin(1)(2)

   $ 252,575      $ 227,389      $ 219,450   
  

 

 

   

 

 

   

 

 

 

Segment gross margin per unit:

      

Texas:

      

Service throughput ($/MMBtu)

   $ 0.70      $ 0.59      $ 0.46   

Oklahoma:

      

Service throughput ($/MMBtu)(2)

   $ 1.00      $ 0.98      $ 0.80   

Volumes:

      

Texas:

      

Service throughput (MMBtu/d)(7)

     795,497        595,641        619,615   

Pipeline throughput (MMBtu/d)

     456,686        328,967        290,627   

Plant inlet volumes (MMBtu/d)

     758,588        504,810        539,633   

NGLs produced (Bbls/d)

     29,147        18,718        17,959   

Oklahoma:

      

Service throughput (MMBtu/d)(7)

     291,532        261,636        262,259   

Plant inlet volumes (MMBtu/d)

     160,406        156,181        163,474   

NGLs produced (Bbls/d)

     17,498        16,251        15,977   

Capital Expenditures:

      

Maintenance capital expenditures

   $ 13,490      $ 9,563      $ 9,728   

Expansion capital expenditures

     259,803        120,941        61,424   
  

 

 

   

 

 

   

 

 

 

Total capital expenditures

   $ 273,293      $ 130,504      $ 71,152   
  

 

 

   

 

 

   

 

 

 

Operations and maintenance expenses:

      

Texas

   $ 38,099      $ 29,236      $ 27,960   

Oklahoma(2)

     26,982        23,955        23,469   

Rocky Mountains

     245        296        48   
  

 

 

   

 

 

   

 

 

 

Total operations and maintenance expenses(2)

   $ 65,326      $ 53,487      $ 51,477   
  

 

 

   

 

 

   

 

 

 

 

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(1) Total segment gross margin is a non-GAAP financial measure. Please read “—How We Evaluate Our Operations” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
(2) Excludes results attributable to our crude oil pipeline and related assets for the year ended December 31, 2009; which are classified as discontinued operations, as discussed in Note 13, “Discontinued Operations,” in our consolidated financial statements included in Item 8 of this report.
(3) During the three months ended September 30, 2011, we recorded a $165 million non-cash impairment charge relating to our investments in Bighorn and Fort Union and a $5 million non-cash impairment charge with respect to a contract under which we provide services to Rocky Mountains producers.
(4) Includes results and volumes associated with our unconsolidated affiliates. The following table summarizes the throughput for the periods indicated:

 

         Year Ended December 31,  
         2011      2010      2009  

Bighorn and Fort Union(a)

  MMBtu/d      604,261         907,809         975,785   

Southern Dome

          

Plant Inlet

  MMBtu/d      11,292         12,522         13,137   

NGLs produced

  Bbls/d      403         449         478   

Webb Duval(b)

  MMBtu/d      51,907         54,879         78,160   

Eagle Ford Gathering

  MMBtu/d      110,827         —           —     

Liberty Pipeline Group

  Bbls/d      4,597         —           —     

 

  (a) The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada’s Bison pipeline upon its start-up in January 2011. Fort Union volumes do not reflect an additional 268,015 MMBtu/d in long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union for year ended December 31, 2011.
  (b) Net of intercompany volumes.

 

(5) Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union, volumes transported using our firm capacity agreements with Wyoming Interstate Gas Company.
(6) Corporate and other includes results attributable to our commodity risk management activities.
(7) “Service throughput” means the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines plus our “pipeline throughput,” which is the volume of natural gas transported or gathered through our pipelines.

Year Ended December 31, 2011 Compared To Year Ended December 31, 2010

Texas Segment Gross Margin. Texas segment gross margin was $184.4 million for 2011 compared to $128.7 million for 2010, an increase of $55.7 million, or 43%. Texas segment gross margin per unit of service throughput increased $0.11 per MMBtu to $0.70 per MMBtu for 2011 compared to $0.59 per MMBtu for 2010, reflecting 27% higher NGL prices and 8% lower natural gas prices compared to 2010, the impact of our fractionation facilities for a full year (operations started in May 2010) which reduced our third-party fractionation costs and enabled us to begin earning fees for providing fractionation services, and an increase in revenue associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays, including $5.1 million in deficiency fees for volumes committed to us but not delivered. The Texas segment’s service throughput, gathering and NGL production increased 34%, 39% and 56%, respectively, and processed volumes increased 50% during 2011. The increase in service throughput is due to volumes from the Eagle Ford Shale and north Barnett Shale Combo plays. The increase in NGL production is due to additional volumes at our Houston Central complex and Saint Jo plant and reflects a 122% increase in volumes behind our Saint Jo plant in the north Barnett Shale Combo play. We restarted our Lake Charles plant in November 2011 and the average inlet volumes and average processing volumes for the Lake Charles plant include 28 days of activity in 2011. Please read Item 1, “Business—Industry Overview—Midstream Contracts.”

 

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Oklahoma Segment Gross Margin. Oklahoma segment gross margin was $105.1 million for 2011 compared to $93.6 million for 2010, an increase of $11.5 million, or 12%. The increase in segment gross margin resulted primarily from a period-over-period increase in NGL prices of 18%, offset by a 8% decrease in natural gas prices. NGL production also increased 8% period-over-period. Oklahoma segment gross margin per unit of service throughput increased $0.02 per MMBtu to $1.00 per MMBtu for 2011 compared to $0.98 per MMBtu for 2010. Service throughput increased 11% between the periods due to volume increases on the Mountain systems. For 2011, plant inlet volumes increased 3% compared to 2010 primarily as a result of the acquisition of the Harrah plant and associated gathering facilities, although that increase was partially offset by normal production declines from our other gathering systems. Please read Item 1, “Business—Industry Overview—Midstream Contracts.

Rocky Mountains Segment Gross Margin. Rocky Mountains segment gross margin was $2.6 million for 2011 compared to $4.4 million for 2010, a decrease of $1.8 million, or 41%. This decrease is primarily the result of increased demand fees we paid under our firm gathering agreements with Fort Union, and our inability to use all of our demand capacity due to a decline in volumes on Bighorn and general production declines in the area.

Corporate and Other. Corporate and other includes our commodity risk management activities and was a $39.6 million loss for 2011 compared to a $0.6 million gain for 2010, a decrease of $40.2 million. The loss for 2011 includes $10.6 million of net cash settlements paid on expired commodity derivative instruments and $29.5 million of non-cash amortization expense relating to the option component of our commodity derivative instruments offset by $0.5 million of unrealized gains on our commodity derivative instruments. The gain for 2010 includes $33.6 million of net cash settlements received on expired commodity derivative instruments offset by $0.6 million of unrealized losses on our commodity derivative instruments and $32.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $65.3 million for 2011 compared to $53.5 million for 2010. The 22% increase is attributable primarily to increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $8.8 million, including expenses for expanded operations related to new Eagle Ford Shale assets and repairs at the Saint Jo plant, and increased payroll, operating costs for new compressors, fuel, utilities and supplies expenses in our Oklahoma segment of $3.0 million, including expenses for the operations of the Burbank and Harrah plants acquired in April 2010 and 2011, respectively.

Depreciation, Amortization and Impairment. Depreciation and amortization totaled $77.6 million for 2011 compared with $62.6 million for 2010, an increase of 24%. This increase relates primarily to a $3.4 million non-cash impairment in south Texas and a $5.0 million non-cash impairment with respect to a contract under which we provide services to Rocky Mountains producers in the third quarter of 2011 as well as additional depreciation and amortization resulting from capital expenditures in 2011, including expenditures relating to acquisition of the Harrah plant, the expansion of the fractionation facility to double the capacity at our Houston Central complex, continued expansion of the gathering system surrounding our Saint Jo plant and the extension of the initial segment of the DK pipeline to the Houston Central complex in Texas.

General and Administrative Expenses. General and administrative expenses totaled $48.7 million for 2011 compared to $40.3 million for 2010. The 21% increase consists primarily of a $5.1 million increase in personnel, compensation and benefits costs, a $1.7 million increase in deferred equity compensation, a $0.7 million increase in tax services, a $0.7 million increase in bad debt expense and a $0.5 million increase in acquisition costs offset by a $0.3 million increase in management fees received from our unconsolidated affiliates.

Equity in Loss/Earnings from Unconsolidated Affiliates. Equity in loss from unconsolidated affiliates totaled $145.3 million for 2011 compared to $20.5 million for 2010, an increase of $124.8 million. The increase consists primarily of a non-cash impairment expense of $165.0 million on our investments in Bighorn and Fort Union, primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and drilling activity in Wyoming’s Powder

 

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River Basin, partially offset by equity earnings of $11.2 million from Eagle Ford Gathering, which began service during the year ended December 31, 2011. Equity in loss from unconsolidated affiliates for 2010 consisted of $28.5 million of equity loss from Bighorn primarily related to a $25.0 million non-cash impairment and $0.3 million of equity loss from our other investments offset by $8.3 million of equity earnings from Fort Union.

Interest and Other Financing Costs. Interest and other financing costs totaled $47.2 million for 2011 compared to $53.6 million for 2010, a decrease of $6.4 million. Interest expense related to our revolving credit facility totaled $10.4 million (including settlements paid under our interest rate swaps of $3.9 million) and $8.5 million (including settlements paid under our interest rate swaps of $5.1 million) for 2011 and 2010, respectively. Interest expense related to our senior notes totaled $45.7 million and $46.3 million for 2011 and 2010, respectively. Interest and other financing costs for 2011 includes unrealized mark-to-market gains of $3.0 million on undesignated interest rate swaps compared to unrealized mark-to-market gains of $1.6 million for 2010. Amortization of debt issue costs totaled $3.8 million for 2011 and 2010. Interest expense was offset by capitalized interest of $9.7 million and $3.4 million for 2011 and 2010, respectively. Average borrowings under our credit arrangements for 2011 and 2010 were $807.6 million and $689.6 million with average interest rates of 7.2% and 10.0%, respectively. Please read “—Liquidity and Capital Resources.”

Year Ended December 31, 2010 Compared To Year Ended December 31, 2009

Texas Segment Gross Margin. Texas segment gross margin was $128.7 million for 2010 compared to $103.6 million for 2009, an increase of $25.1 million, or 24%. Texas segment gross margin per unit of service throughput increased $0.13 per MMBtu to $0.59 per MMBtu for 2010 compared to $0.46 per MMBtu for 2009, reflecting 33% higher NGL prices, the impact of our fractionation facilities for a full year (started in May 2010) and an increase of pipeline throughput associated with fee-based contracts in the Eagle Ford Shale and the north Barnett Shale Combo plays. The increase in segment gross margin was partially offset by a decline of 4% in service throughput for 2010 and higher average natural gas prices, which increased 16% compared to 2009. The Texas segment’s gathering and NGL production increased 13% and 4%, respectively, and processed volumes decreased 6% during 2010. The beneficial pricing environment for NGLs reflects a 131% increase of volumes behind our Saint Jo plant in the north Barnett Shale Combo play. Processed volumes decreased because very limited volumes were available to be processed at our Lake Charles plant. Please read Item 1, “Business—Industry Overview—Midstream Contracts. We started the fractionator at our Houston Central complex in late April 2010, which reduced our third party fractionation costs and enabled us to begin charging fractionation fees to producers, resulting in an increase to our gross margin of $7.5 million during 2010.

Oklahoma Segment Gross Margin. Oklahoma segment gross margin was $93.6 million for 2010 compared to $76.7 million for 2009, an increase of $16.9 million, or 22%. The increase in segment gross margin resulted primarily from period-over-period increases in average natural gas and NGL prices of 28% and 36%, respectively, and a 2% increase in NGL production. Oklahoma segment gross margin per unit of service throughput increased $0.18 per MMBtu to $0.98 per MMBtu for 2010 compared to $0.80 per MMBtu for 2009. The increase in segment gross margin was partially offset by a decrease in plant inlet volumes of 4%. Service throughput remained flat between the periods. For 2010, plant inlet volumes at our Paden plant decreased 11% compared to 2009 primarily as a result of normal production declines on the Stroud gathering system. Please read Item 1, “Business—Industry Overview—Midstream Contracts.

Rocky Mountains Segment Gross Margin. Rocky Mountains segment gross margin was $4.4 million for 2010 compared to $3.3 million for 2009, an increase of $1.1 million, or 33%. This increase is primarily the result of increased compressor rental income from Bighorn.

Corporate and Other. Corporate and other includes our commodity risk management activities and was a gain of $0.6 million for 2010 compared to a $35.9 million gain for 2009. The gain for 2010 includes $33.6 million of net cash settlements received on expired commodity derivative instruments offset by $0.6 million of unrealized losses on our commodity derivative instruments and $32.4 million of non-cash

 

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amortization expense relating to the option component of our commodity derivative instruments. The gain for 2009 includes $68.7 million of net cash settlements received on expired commodity derivative instruments and $4.2 million of unrealized mark-to-market gains on our commodity derivative instruments offset by $37.0 million of non-cash amortization relating to the option component of our commodity derivative instruments.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $53.5 million for 2010 compared to $51.5 million for 2009. The 4% increase is attributable primarily to increased personnel, compensation and benefit costs due to our expanding operations which was partially offset by a reduction in our Oklahoma segment’s compressor rental costs.

Depreciation, Amortization and Impairment. Depreciation, amortization and impairment totaled $62.6 million for 2010 compared to $57.0 million for 2009, an increase of 10%. This increase relates primarily to additional depreciation and amortization resulting from capital expenditures made subsequent to December 31, 2009, including expenditures relating to the initial phase of the fractionation facility at our Houston Central complex, the expansion of our Saint Jo plant and the construction of the initial segment of the DK pipeline in Texas.

General and Administrative Expenses. General and administrative expenses totaled $40.3 million for 2010 compared with $39.5 million for 2009. The 2% increase consists primarily of a $2.2 million increase in personnel, compensation and benefits costs and a $0.5 million increase in deferred equity compensation offset by a $0.9 million decrease in acquisition costs, a $0.7 million increase in management fees received from our unconsolidated affiliates and a $0.3 million gain on the sale of assets.

Equity in Loss/Earnings from Unconsolidated Affiliates. Equity in loss from unconsolidated affiliates totaled $20.5 million for 2010 compared to earnings of $6.9 million for 2009, a decrease of $27.4 million. The decrease consists primarily of non-cash impairment expense of $27.7 million on our investments in Bighorn and Webb Duval resulting from a weak Rocky Mountains pricing environment for natural gas and lack of drilling activity in Wyoming’s Powder River Basin and dry natural gas areas in south Texas partially offset by equity earnings from our other investments.

Interest and Other Financing Costs. Interest and other financing costs totaled $53.6 million for 2010 compared with $55.8 million for 2009, a decrease of $2.2 million, or 4%. Interest expense related to our revolving credit facility totaled $8.5 million (including settlements paid under our interest rate swaps of $5.1 million) and $11.5 million (including settlements paid under our interest rate swaps of $5.4 million) for 2010 and 2009, respectively. Interest expense related to our senior notes totaled $46.3 million and $46.5 million for 2010 and 2009, respectively. Interest and other financing costs for 2010 includes unrealized mark-to-market gains of $1.6 million on undesignated interest rate swaps compared to unrealized mark-to-market gains of $2.8 million for 2009. Amortization of debt issue costs totaled $3.8 million and $4.0 million for 2010 and 2009, respectively. Interest expense was offset by capitalized interest of $3.4 million in each of 2010 and 2009. Average borrowings under our credit arrangements for 2010 and 2009 were $689.6 million and $848.8 million with average interest rates of 10.0% and 7.2%, respectively. Please read “—Liquidity and Capital Resources.”

Cash Flows

The following table summarizes our cash flows as reported in the historical consolidated statements of cash flows found in Item 8 of this report.

 

     Year Ended December 31,  
     2011     2010     2009  
     (In thousands)  

Net cash provided by operating activities

   $ 151,232      $ 123,598      $ 141,318   

Net cash used in investing activities

     (376,314     (156,730     (70,967

Net cash provided by (used in) financing activities

     222,114        48,370        (89,343

 

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Our cash flows are affected by a number of factors, some of which we cannot control. These factors include industry and economic conditions, as well as conditions in the financial markets, prices and demand for our services, volatility in commodity prices or interest rates, effectiveness of our hedging program, operational risks and other factors.

Operating Cash Flows. Net cash provided by operating activities was $151.2 million for 2011 compared to $123.6 million for 2010. The increase in cash provided by operating activities of $27.6 million was attributable to the following changes:

 

   

a $9.2 million increase in cash distributions received from Eagle Ford Gathering, Bighorn, Fort Union and Southern Dome in 2011 compared to 2010;

 

   

a $10.3 million increase in working capital for 2011 compared to 2010;

 

   

risk management activities used $5.0 million less cash flow for 2011 as compared to 2010, primarily because we purchased commodity derivative instruments at a total cost of $11.1 million during 2011, whereas in 2010, we purchased $19.8 million of commodity derivative instruments; and

 

   

a $3.1 million decrease in interest payments for 2011 compared to 2010 as a result of increased capitalized interest.

Net cash provided by operating activities was $123.6 million for 2010 compared to $141.3 million for 2009. The decrease in cash provided by operating activities of $17.7 million was attributable to the following changes:

 

   

risk management activities used an additional $16.6 million of cash flow for 2010 as compared to 2009, primarily because we purchased commodity derivative instruments totaling $19.8 million during 2010, whereas in 2009, we purchased $6.9 million of commodity derivative instruments;

 

   

a $6.1 million decrease in working capital in 2010 as compared to 2009;

partially offset by:

 

   

a $3.5 million decrease in interest payments for 2010 compared to 2009 as a result of lower average borrowings; and

 

   

a $1.5 million increase in cash distributions received from Bighorn and Fort Union in 2010 compared to 2009.

Investing Cash Flows. Net cash used in investing activities was $376.3 million for 2011. Investing activities for 2011 included (i) $258.1 million of capital expenditures related to our Eagle Ford Shale growth strategy, the acquisition of the Harrah plant in Oklahoma and well connections attaching volumes in new areas and (ii) $122.0 million of investments in Eagle Ford Gathering, Liberty Pipeline Group, Webb Duval, Double Eagle Pipeline and Bighorn offset by $3.8 million of distributions from Bighorn and Southern Dome in excess of equity earnings.

Net cash used in investing activities was $156.7 million for 2010. Investing activities for 2010 included (i) $127.7 million of capital expenditures related to the expansion of our Saint Jo plant and construction of upstream gathering lines, right-of-way acquisition, construction of the DK pipeline and start-up of our fractionator at the Houston Central complex in Texas, and completion of the Burbank plant and installation of treating and compression facilities in Oklahoma, as well as constructing well interconnects to attach volumes in new areas and (ii) $33.0 million of investments in Eagle Ford Gathering offset by (i) $3.5 million of distributions from Bighorn and Southern Dome in excess of equity earnings and (ii) other investing activities of $0.5 million.

Net cash used in investing activities was $71.0 million for 2009. Investing activities for 2009 included (i) $79.3 million of capital expenditures related to the construction of our Saint Jo plant and related projects, progress payments for the purchase of compression and constructing well interconnects to attach volumes in new

 

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areas, (ii) $4.2 million of investment in Bighorn and (iii) other investing activities of $2.4 million, offset by (i) $8.8 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings and (ii) $6.1 million of proceeds from the sale of assets, primarily relating to our crude oil pipeline operations.

Financing Cash Flows. Net cash provided by financing activities totaled $222.1 million during 2011 and included (i) net borrowings under our revolving credit facility of $375 million, (ii) issuance of our senior unsecured notes due 2021 of $360 million and (iii) proceeds from the exercise of unit options of $3.2 million offset by (i) distributions to our unitholders of $153.1 million, (ii) tender and redemption of our senior unsecured notes due 2016 of $332.6 million, (iii) bond tender and consent premiums of $14.6 million and (iv) deferred financing costs of $15.8 million.

Net cash provided by financing activities totaled $48.4 million during 2010 and included (i) proceeds from our private placement of Series A convertible preferred units net of underwriting discounts and commissions and fees of $285.2 million, (ii) net proceeds from our public offering of common units (including units issued upon the underwriters’ exercise of their option to purchase additional units) of $164.3 million and (iii) proceeds from the exercise of unit options of $5.4 million offset by (i) net repayments under our revolving credit facility of $260 million, (ii) distributions to our unitholders of $145.5 million and (iii) deferred financing costs of $1.0 million.

Net cash used in financing activities totaled $89.3 million during 2009 and included (i) net borrowings under our revolving credit facility of $50.0 million and (ii) proceeds from the exercise of unit options of $0.7 million offset by (i) the retirement of $14.3 million aggregate principal amount of our 8.125% senior unsecured notes due 2016 and (ii) distributions to our unitholders of $125.7 million.

Liquidity and Capital Resources

Sources of Liquidity. Cash generated from operations (including distributions from our unconsolidated affiliates), borrowings under our revolving credit facility and funds from equity and debt offerings are our primary sources of liquidity. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on our revolving credit facility and senior unsecured notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Generally, our operating cash flow includes payments for our services on a monthly basis; in the case of deficiency fees for committed volumes not delivered, however, we receive payments at the end of quarterly or annual commitment periods. We expect to fund long-term cash requirements for expansion projects and acquisitions though several sources, including operating cash flows, borrowings under our revolving credit facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions.

Please read Item 1, “Business—Industry Overview—Recent Developments,” for discussions of our January 2012 public equity offering and our February 2012 public debt offering.

Outlook. Recent commodity prices and financial market conditions have supported significant opportunities for volume growth from shale resource plays, while drilling activity around our assets in the Powder River Basin and in areas where producers employ conventional drilling techniques has been minimal. It remains unclear when producers in these areas will undertake sustained increases in drilling activity. Our ability to generate cash from operations and to comply with the covenants under our debt instruments would be adversely affected if we experienced declining volumes in combination with unfavorable commodity prices over a sustained period.

We purchase commodity derivatives during favorable pricing environments so that the cash from their settlements will help to offset the effects of unfavorable pricing environments in the future. We purchased commodity derivatives related to 2012 and 2013 in late 2010 and 2011 to hedge against potential future declines in commodity prices.

 

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We believe that our cash from operations, cash on hand and our revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the next 12 months. If our plans change or our assumptions prove inaccurate, or if we make further acquisitions, we may need to raise additional capital.

Acquisitions and organic expansion have been, and our management believes will continue to be, key elements of our business strategy. In addition, we continue to consider opportunities for strategic greenfield projects. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. We intend to finance growth projects and acquisitions primarily through the issuance of debt and equity. To consummate larger acquisitions or capital projects, we will require access to additional capital on competitive terms. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets, and other financial and business factors, many of which are beyond our control.

Capital Expenditures. Our business is capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

 

   

maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

 

   

expansion capital expenditures, which are capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance.

During 2011, our capital expenditures totaled $273.3 million, consisting of $13.5 million of maintenance capital and $259.8 million of expansion capital. We used funds from operations and borrowings under our revolving credit facility to fund our capital expenditures. Our expansion capital expenditures related mainly to (i) the fractionation expansion and cryogenic processing upgrade at our Houston Central complex, (ii) extension of our DK pipeline to the Houston Central complex, (iii) our acquisition of the Harrah plant, (iv) construction of lateral pipelines and well connections to attach volumes from the Eagle Ford Shale and the north Barnett Shale Combo plays, (v) the addition of an amine treater to the Saint Jo complex, (vi) the conversion of the Goebel pipeline to condensate service and (vii) additional treating and compression on our Mountains systems in Oklahoma. We anticipate incurring approximately $301 million in additional expansion capital expenditures in 2012 to complete these projects and to enhance the capabilities and capacities of our current asset base and expanding into condensate gathering and transportation. Based on our current scope of operations, we anticipate incurring approximately $12 million to $14 million of maintenance capital expenditures over the next 12 months.

On April 1, 2011, we purchased the Harrah plant, a 38,000 Mcf/d natural gas processing plant, and other related gathering and processing facilities in Oklahoma County, Oklahoma, for $16.1 million, funded with cash on hand. Our Oklahoma segment historically delivered natural gas to the Harrah plant for processing. This acquisition enables us to increase our margin on gas processed at the Harrah plant and provides us with additional cryogenic processing capacity.

Investment in Unconsolidated Affiliates. During 2011, our capital contributions to our unconsolidated affiliates totaled $122.0 million and consisted primarily of contributions to Eagle Ford Gathering for its construction of gathering pipelines and the related crossover project and Liberty Pipeline Group for construction

 

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of its NGL pipeline. We anticipate making additional cash contributions of approximately $17 million to Eagle Ford Gathering for completion of the pipeline, crossover projects and LaSalle compressor station, $4 million to Liberty Pipeline Group for completion of the NGL pipeline facilities and $80 million to Double Eagle Pipeline for the construction of the condensate/crude gathering system.

Cash Distributions. The amount needed to pay the current distribution of $0.575 per unit, or $2.30 per unit annualized, to our common unitholders is as follows (in thousands):

 

     One Quarter      Four Quarters  

Common units(1)(2)

   $ 42,064       $ 168,255   
  

 

 

    

 

 

 

 

(1) Includes distributions on restricted common units and phantom units issued under our Long-Term Incentive Plan. Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of January 26, 2012, we had 43,800 outstanding restricted units and 993,458 outstanding phantom units.
(2) Includes 5,750,000 common units issued in our January 2012 offering.

Contractual Cash Obligations. A summary of our contractual cash obligations as of December 31, 2011 is as follows:

 

     Payment Due by Period  

Type of Obligation

   Total
Obligation
     Less than
1 Year
     1-3 Years      3-5 Years      More than
5 years
 
     (In thousands)  

Long-term debt

   $ 994,525       $ —         $ —         $ 385,000       $ 609,525   

Interest(1)

     408,329         55,627         111,131         105,308         136,263   

Gathering, transportation and fractionation firm commitments(2)

     195,776         17,021         48,633         44,713         85,409   

Operating leases

     15,723         2,639         3,495         3,030         6,559   

Capital expenditures and investments in unconsolidated affiliates(3)

     416,000         416,000         —           —           —     
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

Total contractual cash obligations

   $ 2,030,353       $ 491,287       $ 163,259       $ 538,051       $ 837,756   
  

 

 

    

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) These amounts exclude estimates of the effect of our interest rate swap contracts on our future interest obligations. As of December 31, 2011, the fair value of our interest rate swap contracts, which expire between January 2012 and October 2012, totaled $3.6 million.
(2) These amounts reflect commitments to third parties for payments whether or not we use the associated services.
(3) Represents commitments as of December 31, 2011 discussed above in—“Capital Expenditures” and—Investments in Unconsolidated Affiliates.

Our Indebtedness

As of December 31, 2011 and 2010, our aggregate outstanding indebtedness totaled $994.5 million and $592.2 million, respectively, and we were in compliance with the financial debt covenants under our revolving credit facility and our incurrence covenants under the indentures governing our senior unsecured notes.

Credit Ratings. Moody’s Investors Service has assigned a Corporate Family rating of Ba3 with a negative outlook, a B1 rating for our senior unsecured notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a stable outlook and a B+ rating for our senior unsecured notes.

 

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Revolving Credit Facility. As of December 31, 2011, we had $385 million in outstanding borrowings under our $700 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent.

Our revolving credit facility matures on June 10, 2016 and includes 19 lenders with commitments ranging from $25 million to $48 million, with the largest commitment representing 6.9% of the total commitments. Future borrowings under our revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restriction so long as we are in compliance with its terms, including the financial covenants described below. Our revolving credit facility provides for up to $100 million in standby letters of credit. As of December 31, 2011 and 2010, we had no letters of credit outstanding. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position.

Our revolving credit facility obligations are secured by first priority liens on substantially all of our assets and the assets of our 100% owned subsidiaries (except for our equity interests in joint venture entities other than Webb Duval and Southern Dome), all of which are guarantors under the revolving credit facility. Our less than 100% owned subsidiaries have not pledged their assets as security or guaranteed our obligations under the revolving credit facility.

Annual interest under the revolving credit facility is determined, at our election, by reference to (i) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable margin ranging from 2.00% to 3.25% per annum, or (ii) the higher of the federal funds rate plus 0.5%, the prime rate and LIBOR plus 1.0% plus, in each case, an applicable margin ranging from 1.0% to 2.25%. The effective average interest rate on borrowings under the revolving credit facility for 2011, 2010 and 2009 was 5.6%, 8.9% and 4.8%, respectively, and the quarterly commitment fee on the unused portion of the revolving credit facility for those periods, respectively, was 0.375%, 0.25% and 0.25%.

The revolving credit facility contains various covenants (including certain subjective representations and warranties) that, subject to exceptions, limit our and subsidiary guarantors’ ability to grant liens; make loans and investments; make distributions other than from available cash (as defined in our limited liability company agreement); merge or consolidate with or into a third party; or engage in certain asset dispositions, including a sale of all or substantially all of our assets. Additionally, the revolving credit facility limits our and our subsidiary guarantors’ ability to incur additional indebtedness, subject to exceptions, including (i) purchase money indebtedness and indebtedness related to capital or synthetic leases, (ii) unsecured indebtedness qualifying as subordinated debt and (iii) certain privately placed or public term unsecured indebtedness.

The revolving credit facility also contains financial covenants, which, among other things, require us and our subsidiary guarantors, on a consolidated basis, to maintain:

 

   

a maximum consolidated leverage ratio (total debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 5.25 to 1.0. Subject to conditions and limitations described in the amended credit agreement, up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of projected EBITDA attributable to material capital projects (generally, capital projects expected to exceed $20 million) then under construction, including our net share of projected EBITDA attributable to capital projects pursued by joint ventures in which we own interests (“Material Project EBITDA”);

 

   

a maximum senior secured leverage ratio (total senior secured debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 4.0 to 1.0. Up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of Material Project EBITDA; and

 

   

a minimum consolidated interest coverage ratio (Consolidated EBITDA to interest as defined in the amended credit agreement) as of the end of any fiscal quarter may not be less than 2.50 to 1.00.

 

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At December 31, 2011, our ratio of total debt to EBITDA was 4.23x, our ratio of senior secured debt to EBITDA was 1.65x and our ratio of EBITDA to interest expense was 3.98x. Based on our ratio of total debt to EBITDA at December 31, 2011, we have approximately $241 million of available borrowing capacity under the revolving credit facility before we reach the maximum total debt to EBITDA ratio of 5.25 to 1.0.

Our revolving credit facility also contains customary events of default, including the following:

 

   

failure to pay any principal when due, or within specified grace periods, any interest, fees or other amounts;

 

   

failure to perform or otherwise comply with the covenants in the credit agreement or other loan documents, subject to grace periods in some cases;

 

   

default on the payment of any other indebtedness in excess of $35 million, or in the performance of any obligation or condition with respect to such indebtedness, beyond the applicable grace period if the effect of the default is to permit or cause the acceleration of the indebtedness;

 

   

bankruptcy or insolvency events involving us or our subsidiaries;

 

   

the entry of, and failure to pay, one or more adverse judgments in excess of $35 million upon which enforcement proceedings are brought or are not stayed pending appeal; and

 

   

a change of control (as defined in the revolving credit facility).

If we failed to comply with the financial or other covenants under our revolving credit facility or experienced a material adverse effect on our operations, business, properties, liabilities or financial or other condition, we would be unable to borrow under our revolving credit facility, and could be in default after specified notice and cure periods. If an event of default exists under the revolving credit facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the revolving credit facility.

Senior Notes. As of December 31, 2011, our aggregate outstanding indebtedness under our senior notes due 2018 and 2021 totaled $609.5 million. Interest on the senior notes is payable semi-annually.

On April 5, 2011, we closed a public offering of $360 million in aggregate principal amount of 7.125% senior unsecured notes due 2021. We used the net proceeds to fund a tender offer for all of our outstanding 8.125% senior secured notes due 2016 and a subsequent redemption of all of these senior notes not purchased in the tender offer, and to provide working capital and for general corporate purposes.

On February 7, 2012, we completed a registered underwritten offering of an additional $150 million aggregate principal amount of 7.125% senior notes due 2021 at 102.25% of their principal amount for net proceeds of approximately $150.1 million. These notes are an additional issue of our existing senior notes due 2021 and are issued under the same indenture and are part of the same series. We used net proceeds from the offering to repay a portion of the outstanding indebtedness under our revolving credit facility.

The senior notes are jointly and severally guaranteed by all of our 100% owned subsidiaries (other than Copano Energy Finance Corporation, the co-issuer of the Senior Notes). The subsidiary guarantees rank equally in right of payment with all of our guarantor subsidiaries’ existing and future senior indebtedness, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all of our guarantor subsidiaries’ existing and future secured indebtedness (including under our revolving credit facility) to the extent of the value of the assets securing that indebtedness, and all liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries).

The senior notes are redeemable, in whole or in part and at our option, at stated redemption prices plus accrued and unpaid interest to the redemption date. If we undergo a change in control, we must give the holders of Senior Notes an opportunity to sell us their notes at 101% of the face amount, plus accrued and unpaid interest to date.

 

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The indentures governing our senior notes include customary covenants that limit our and our subsidiary guarantors’ abilities to, among other things:

 

   

sell assets;

 

   

redeem or repurchase equity or subordinated debt;

 

   

make investments;

 

   

incur or guarantee additional indebtedness or issue preferred units;

 

   

create or incur liens;

 

   

enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;

 

   

consolidate, merge or transfer all or substantially all of our assets;

 

   

engage in transactions with affiliates;

 

   

create unrestricted subsidiaries; and

 

   

enter into sale and leaseback transactions.

In addition, the indentures governing our senior notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the senior unsecured notes indentures) is at least 1.75x. At December 31, 2011, our ratio of EBITDA to fixed charges was 3.38x.

These covenants are subject to customary exceptions and qualifications. Additionally, if the senior notes achieve an investment grade rating from each of Moody’s Investors Service and Standard & Poor’s Ratings Services, many of these covenants will terminate.

Impact of Inflation

The midstream natural gas industry experienced increasing costs for chemicals, utilities, materials and supplies, labor and equipment in recent years, due in part to increased activity in the energy sector and high commodity prices. After commodity prices declined sharply in late 2008, operating costs began a correction, and by the end of 2009, these costs had stabilized. Although the impact of inflation has not been material in recent years, it remains a factor in the midstream natural gas industry and in the United States economy in general. To the extent permitted by competition, regulation and our existing agreements, we may pass along increased costs to our customers in the form of higher fees.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2011 and 2010.

Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board (“FASB”), issued Accounting Standards Update (“ASU”), 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of members’ capital. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective beginning with our first quarterly filing in 2012. We do not expect the guidance to impact our consolidated financial results, as the only required change is the format of presentation.

 

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In May 2011, the FASB issued ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards,” which provides a consistent definition of fair value and requirements for measurement of and disclosure about fair value between GAAP and International Financial Reporting Standards. This new guidance changes some of the existing fair value measurement principles and disclosure requirements and will be effective beginning with our first quarterly filing in 2012. We do not expect this guidance to impact our consolidated financial results, as the only change will be additional disclosure on our fair value measures.

We have reviewed other recently issued, but not yet adopted, accounting standards and updates in order to determine their potential effects, if any, on our consolidated results of operations, financial position and cash flows. Most of the recent updates represented technical corrections to the existing accounting literature or applied to other industries and are not expected to have a material impact on our consolidated cash flows, results of operations or financial position.

Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives, but involve an implementation and interpretation of existing rules, and the use of judgment applied to the specific set of circumstances existing in our business. We make every effort to properly comply with all applicable rules on or before their adoption, and we believe the proper implementation and consistent application of the accounting rules are critical. For further details on our accounting policies, please read Notes 2 and 3 to our consolidated financial statements included in Item 8 of this report.

Investments in Unconsolidated Affiliates

We own a 62.5% equity investment in Webb Duval, a majority interest in Southern Dome, a 51% equity investment in Bighorn, a 37.04% equity investment in Fort Union, a 50% equity investment in Eagle Ford Gathering, a 50% equity investment in Liberty Pipeline Group and a 50% equity investment in Double Eagle Pipeline. Although we are the managing partner or member in each of these equity investments and own a majority interest in some of these equity investments, we account for these investments using the equity method of accounting because the remaining general partners or members have substantive participating rights with respect to the management of each of these equity investments. Equity in earnings (loss) from our unconsolidated affiliates is included in income from operations as the operations of each of our unconsolidated affiliates are integral to our operations.

We periodically reevaluate our equity-method investments to determine whether current events or circumstances warrant adjustments to our carrying value in accordance with the FASB, Accounting Standard Codification (“ASC”) 323 “Investments—Equity Method and Joint Ventures.” When indicators of impairment are present, we perform an impairment test to determine if adjustment to our carrying value is necessary. The impairment test for our investments in unconsolidated affiliates requires that we consider whether the fair value of our equity investment as a whole, not the underlying net assets, has declined, and if so, whether that decline is other than temporary. During the three months ended September 30, 2011, we recorded a $165 million non-cash impairment charge relating to our investments in Bighorn and Fort Union primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve. We developed the fair value of our investments in Bighorn and Fort Union (please read Note 9 to our consolidated financial statements included in Item 8 of this report) using a probability weighted discounted cash flow model using a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures.

As of December 31, 2011, based on forecasted pricing in the region updated during our impairment analysis at September 30, 2011, we believe it is probable that producers on our dedicated acreage will increase drilling

 

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and production in the future when prices are sufficient to support substantial drilling and completion activity, and that we will recover our revalued investments in Bighorn and Fort Union. If the assumptions underlying our expectations prove incorrect and volumes do not recover either due to a decreased drilling activity or a weaker than forecasted pricing environment, we ultimately would be required to record an additional impairment of our interests in Bighorn, Fort Union, or both.

Impairment of Long-Lived Assets

In accordance with ASC 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change. During the three months ended September 30, 2011, we recorded a $5 million non-cash impairment charge with respect to a contract under which we provide services to Rocky Mountains producers primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve. During the three months ended December 31, 2011, we recorded a $3.4 million non-cash impairment charge relating to assets in south Texas.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset, including future commodity prices and estimated future natural gas production in the region (which is dependent in part on commodity prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

 

   

changes in general economic conditions in which our assets are located;

 

   

the availability and prices of natural gas supply;

 

   

improvements in exploration and production technology;

 

   

the finding and development cost for producers to exploit reserves in a particular area;

 

   

our ability to negotiate favorable agreements with producers and customers;

 

   

Availability of downstream natural gas and NGL markets;

 

   

our dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

 

   

competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. An estimate of the sensitivity of these assumptions to our estimated future undiscounted cash flows used in our impairment review is not practicable given the extensive array of our assets and the number of assumptions involved in these estimates. However, based on current period assumptions, a decrease in our estimated future undiscounted cash flows associated with certain assets of 10% could result in a potential impairment of these assets.

 

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Revenue Recognition

Using the revenue recognition criteria of evidence of an arrangement, delivery of a product and the determination of price, our natural gas and NGL revenue is recognized in the period when the physical product is delivered to the customer and in an amount based on the pricing terms of an executed contract. Our transportation, compression, processing, fractionation and other revenue is recognized in the period when the service is provided and includes our fee-based service revenue including processing under firm capacity arrangements. In addition, collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers’ financial position and their ability to pay.

Our sale and purchase arrangements are primarily accounted for on a gross basis in the statements of operations as natural gas sales and costs of natural gas, respectively. These transactions are contractual arrangements that establish the terms of the purchase of natural gas at a specified location and the sale of natural gas at a different location on the same or on another specified date. All transactions require physical delivery of the natural gas, and transfer of the risk and reward of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk and counterparty nonperformance risk.

On occasion, we enter into buy/sell arrangements that are accounted for on a net basis in the statements of operations as either a net natural gas sale or a net cost of natural gas, as appropriate. These purchase and sale transactions are generally detailed either jointly, in a single contract or separately, in individual contracts that are entered into concurrently or in contemplation of one another with a single or multiple counterparties.

Our contract mix reflects a variety of pricing terms typical for the midstream industry, with varying levels of commodity price sensitivity, including fee-based, percent-of-proceeds, percent-of-index and keep-whole terms. In addition to compensating us for gathering, transportation, processing, or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration, nitrogen rejection or other services. Generally:

 

   

our margins from fee-based pricing are directly related to the volumes of natural gas or NGLs that flow through our systems and are not directly affected by commodity prices;

 

   

our margins from percent-of-proceeds (including percent-of-liquids) pricing and percent-of-index pricing for lean gas that does not require processing are generally directly related to the prices for natural gas, NGLs or both; in other words, our margins increase or decrease as prices increase or decrease;

 

   

our margins from keep-whole pricing and percent-of-index pricing involving gas that we process are related not only to natural gas and NGL prices but also to the spread between natural gas and NGL prices. As NGL prices increase relative to natural gas prices, our margins increase, and if NGL prices decrease relative to natural gas prices, our margins decrease. Our keep-whole contracts include terms that help us avoid incurring losses that would result if NGL prices fell near or below natural gas prices, such as allowing us to charge fees and reduce the volume of NGLs we recover during unfavorable pricing environments. Also, to the extent our contract entitles us to keep extracted NGLs, we may share a portion of our processing margin with the counterparty when processing margins are favorable.

In addition, some of our fee-based and percent-of-proceeds contracts include “fixed recovery” provisions, which operate in conjunction with the contract’s main pricing terms. Under fixed recovery terms, we determine the amount payable, or the volumes of residue gas and NGLs deliverable, to the counterparty based on contractual NGL recovery factors. Fixed recovery terms can affect our margins to the extent that our actual recoveries vary from the agreed NGL recovery factor. If we exceed fixed recoveries when processing margins are favorable, our margins will benefit to the extent of the difference. However, our margins will decrease to the extent we do not meet the NGL recovery factor in a favorable processing margin environment, and we could incur losses. If NGL prices are unfavorable relative to natural gas prices, we would be able to increase our margins by reducing our recoveries.

 

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Risk Management Activities

ASC 815 “Derivatives and Hedging,” as amended, establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. In accordance with ASC 815, we recognize all derivatives as either risk management assets or liabilities in our consolidated balance sheets and measure those instruments at fair value. If the financial instruments meet the hedging criteria, changes in fair value will be recognized in earnings for fair value hedges and in other comprehensive income for the effective portion of cash flow hedges. Ineffectiveness in cash flow hedges is recognized in earnings in the period in which the ineffectiveness occurs. Gains and losses on cash flow hedges are reclassified to operating revenue as the forecasted transactions impact earnings. We included changes in our risk management activities in cash flow from operating activities on the consolidated statements of cash flows.

We use financial instruments such as puts, calls, swaps and other derivatives to mitigate the risks to our cash flow and profitability resulting from changes in commodity prices and interest rates. We recognize these transactions as assets and liabilities on our consolidated balance sheets based on the instrument’s fair value. We estimate the fair value of our financial derivatives using valuation models based on whether the inputs to those valuation techniques are observable or unobservable. For further details on our risk management activities, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of this report.

 

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

Commodity Price Risk

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices as a function of the contract terms under which we are compensated for our services or pay third parties for their services and primarily results from: (i) processing natural gas at our plants or third-party plants, (ii) purchasing and selling or gathering and transporting natural gas at index-related prices and (iii) the cost of transporting and fractionating NGLs. Generally, natural gas and NGL prices affect our Texas and Oklahoma segments directly because some of our contracts in those segments have commodity-sensitive pricing terms. In addition, natural gas and NGL prices, and to a lesser degree, crude oil prices, also affect all of our segments indirectly because they influence exploration and production activity, which underlie the demand for our services.

Our Contracts

Our contract mix reflects a variety of pricing terms typical for the midstream industry, with varying levels of commodity price sensitivity, including fee-based, percent-of-proceeds, percent-of-index and keep-whole terms. Please refer to Item 1, “Business—Industry Overview—Midstream Contracts” for detailed descriptions of these arrangements. In addition to compensating us for gathering, transportation, processing, or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration, nitrogen rejection or other services. Generally:

 

   

our margins from fee-based pricing are directly related to the volumes of natural gas or NGLs that flow through our systems and are not directly affected by commodity prices;

 

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our margins from percent-of-proceeds (including percent-of-liquids) pricing and percent-of-index pricing for lean gas that does not require processing are generally directly related to the prices for natural gas, NGLs or both; in other words, our margins increase or decrease as prices increase or decrease;

 

   

our margins from keep-whole pricing and percent-of-index pricing involving gas that we process are related not only to natural gas and NGL prices but also to the spread between natural gas and NGL prices. As NGL prices increase relative to natural gas prices, our margins increase, and if NGL prices decrease relative to natural gas prices, our margins decrease. Our keep-whole contracts include terms that help us avoid incurring losses that would result if NGL prices fell near or below natural gas prices, such as allowing us to charge fees and reduce the volume of NGLs we recover during unfavorable pricing environments. Also, to the extent our contract entitles us to keep extracted NGLs, we may share a portion of our processing margin with the counterparty when processing margins are favorable.

In addition, some of our fee-based and percent-of-proceeds contracts include “fixed recovery” provisions, which operate in conjunction with the contract’s main pricing terms. Under fixed recovery terms, we determine the amount payable, or the volumes of residue gas and NGLs deliverable, to the counterparty based on contractual NGL recovery factors. Fixed recovery terms can affect our margins to the extent that our actual recoveries vary from the agreed NGL recovery factor. If we exceed fixed recoveries when processing margins are favorable, our margins will benefit to the extent of the difference. However, our margins will decrease to the extent we do not meet the NGL recovery factor in a favorable processing margin environment, and we could incur losses. If NGL prices are unfavorable relative to natural gas prices, we would be able to increase our margins by reducing our recoveries.

The table below illustrates the commodity sensitivity affecting our gross margin, as percentage of our quarterly total segment gross margin and our share of the gross margin from each of our unconsolidated affiliates. The contract types presented indicate what portion of our gross margin was generated under each of the pricing terms listed, rather than under categories of contracts. As noted above, many of our contracts use a combination of pricing terms to help reduce our commodity price risk; therefore, a single contract will likely contribute to multiple categories in the table below.

 

Contract Pricing(1)

   Q1 2011     Q2 2011     Q3 2011     Q4 2011  

Fee-based

     41     41     43     47

Percentage-of-proceeds(2)

     32     33     31     27

Keep-whole and other(3)

     39     40     36     41

Net hedging(4)

     (12 )%      (14 )%      (10 )%      (15 )% 

 

(1) Gross margin attributable to percent-of-index arrangements for lean gas is immaterial and has not been set forth separately.
(2) Gross margin attributable to percentage-of proceeds pricing increases as commodity prices increase.
(3) Gross margin attributable to keep-whole pricing terms increases if NGL prices increase relative to natural gas prices, and decreases if NGL prices decline relative to natural gas prices. “Other” consists of percent-of-index arrangements involving rich gas and the effects of variations from agreed fixed recoveries.
(4) Net impact of our commodity derivative instruments to total segment gross margin.

Our Operating Segments

Texas. Our Texas pipeline systems purchase natural gas and transport for resale and also transport and provide other services on a fee-for-service basis. Many of the contracts we executed in 2011 have been fee-based and have provided for volume commitments by producers, under which the producer is obligated to deliver an agreed volume of natural gas and to pay a “deficiency fee” to the extent the producer delivers less than the agreed volume. The fees we charge to transport natural gas for the accounts of others are primarily fixed, but our Texas contracts also include a percentage-of-index component in a number of cases.

 

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While we have increasingly focused on obtaining fee-based arrangements, a significant portion of the gas processed by the Texas segment is still processed under commodity sensitive arrangements.

Oklahoma. A majority of the processing contracts in our Oklahoma segment are percentage-of-proceeds arrangements. Our Oklahoma segment also has fixed-fee contracts and percentage-of-index contracts.

Rocky Mountains. Substantially all of our Rocky Mountains contractual arrangements as well as the contractual arrangements of Fort Union and Bighorn are fee-based arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. We have experienced the effects of indirect commodity price risk in our Rocky Mountains operations, as sustained low natural gas prices have discouraged drilling activity, which has caused volume declines for our producer services and on Bighorn and Fort Union.

Other Commodity Price Risks. Although we seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations, we experience imbalances between our natural gas or NGL purchases and sales from time to time. For example, a producer could fail to deliver or deliver in excess of contracted gas volumes, or a customer could take more or less than its contracted volumes. We also experience imbalances relating to operational factors such as accumulation of condensate in our pipelines, which reduces the thermal equivalent value of the gas being gathered or transported. We periodically recover and sell the condensate. To the extent our purchases and sales of gas or NGLs are not balanced, we face increased exposure to commodity prices with respect to the imbalance.

We purchase and sell natural gas and NGLs under a variety of pricing arrangements. We generally purchase gas, mixed NGLs or both from producers at index-based prices, in some cases less an agreed discount or fee, or at prices based on our actual resale prices. We sell gas by reference to first of the month index prices, daily index prices or a weighted average of index prices over a given period. We resell mixed NGLs or purity products at index-based prices, in some cases less a discount or fee to the purchaser. Our goal is to minimize commodity price risk by aligning the combination of pricing methods and indices under which we purchase gas and NGLs with the combination under which we sell gas and NGLs, although it is not always possible to do so.

Basis risk is the risk that the value of a hedge may not move in tandem with the value of the actual price exposure that is being hedged. Any disparity in terms, such as product, time or location, between the hedge and the underlying exposure creates the potential for basis risk. Our long position in natural gas in Oklahoma can serve as a hedge against our short position in natural gas in Texas. To the extent we rely on natural gas from our Oklahoma segment, which is priced primarily on the CenterPoint East index, to offset a short position in natural gas in our Texas segment, which is priced on the Houston Ship Channel index, we are subject to basis risk. In addition, we are subject to basis risk to the extent we hedge Oklahoma NGL volumes because, due to the limited liquidity in the forward market for Conway-based hedge instruments, we use Mont Belvieu-priced hedge instruments for our Oklahoma NGL volumes. The CenterPoint East and Houston Ship Channel indices and the Mont Belvieu and Conway indices historically have been highly correlated; however, CenterPoint East and Houston Ship Channel displayed greater variability in 2009 before returning to a correlation more consistent with their historical pattern in late 2009 and through 2011. Mont Belvieu and Conway have continued to show variability, and the basis has continued to widen throughout 2011.

Sensitivity. In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $1.1 million to our total segment gross margin for the year ended December 31, 2011. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in a corresponding decrease of approximately $0.1 million to our total segment gross margin, and vice versa, for the year ended December 31, 2011. These relationships are not necessarily linear.

 

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Risk Management Oversight

We seek to mitigate the price risk of natural gas and NGLs, and our interest rate risk discussed below under “—Interest Rate Swaps”, through the use of derivative instruments. These activities are governed by our risk management policy. Our Risk Management Committee is responsible for our compliance with our risk management policy and consists of our Chief Executive Officer, Chief Financial Officer, General Counsel and the President of any operating segment. The Audit Committee of our Board of Directors monitors the implementation of our risk management policy, and we have engaged an independent firm to monitor compliance with our risk management policy on a monthly basis.

Our risk management policy provides that derivative transactions must be executed by our Chief Financial Officer or his designee and must be authorized in advance of execution by our Chief Executive Officer.

As of December 31, 2011, we were in compliance with our risk management policy.

Commodity Price Hedging Activities

Permitted Derivative Instruments. Our risk management policy allows our management to:

 

   

purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on WTI crude oil to hedge NGLs produced or condensate collected by us or an entity or asset to be acquired by us if a binding purchase and sale agreement has been executed (a “Pending Acquisition”);

 

   

purchase put or call options, enter into collars (purchase of a put together with the sale of a call) or “call or put spreads” ((i) purchase of a call and a sale of a call at a higher strike price or (ii) purchase of a put and a sale of a put at a lower strike price), fixed-for-floating swaps or floating-for-floating swaps (basis swaps) on natural gas at Henry Hub, Houston Ship Channel or other highly liquid points relevant to our operations or a Pending Acquisition;

 

   

purchase put options, enter into collars or “put spreads” (purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps or floating-for-floating swaps (basis swaps) on NGLs to which we or a Pending Acquisition has direct price exposure, priced at Mont Belvieu or Conway; and

 

   

purchase put options and collars and/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for NGLs (as a mixed Bbl or as a separate product) for which we or a Pending Acquisition has direct price exposure.

Limitations. Our policy also limits the maturity and notional amounts of our derivatives transactions as follows:

 

   

Maturities with respect to the purchase of any crude oil, natural gas, NGLs, fractionation spread or processing margin spread hedge instruments must be limited to five years from the date of the transaction;

 

   

Except as provided below under “Exception to Volume Limitations,” we may not (i) purchase crude oil or NGLs put options, (ii) purchase natural gas put or call options, (iii) purchase fractionation spread or processing margin spread put options or (iv) enter into any crude oil, natural gas or NGLs spread options permitted by the policy if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged commodity would exceed 80% of the projected requirements or output, as applicable, for the hedged period. We are required to divest outstanding hedge positions only to the extent net notional hedged volumes with respect to an underlying hedged commodity exceed 100% of the projected requirements or output, as applicable, for the hedged period;

 

   

The aggregate volumetric exposure associated with swaps (other than basis swaps), collars and written calls relating to any product must not exceed the lesser of 50% of the aggregate hedged position or 35% of the projected requirements or output with respect to such product; and

 

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We may not enter into a basis swap if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged basis would exceed 80% of the projected requirements or output, as applicable, for the hedged period. We are required to divest outstanding basis swaps only to the extent net notional hedged volumes with respect to an underlying hedged basis exceed 100% of the projected requirements or output, as applicable, for the hedged period.

Our policy of limiting swaps (other than basis swaps) relating to any product to the lesser of a percentage of our overall hedge position or a percentage of the related projected requirements or output is intended to avoid risk associated with potential fluctuations in output volumes that may result from operational circumstances.

Exception to Volume Limitations. The volume limitations under our risk management policy provide that the notional amounts of put options with strike prices that are greater than 33% out-of-the-money (market price exceeds strike price by greater than 33%) may be excluded from the notional volume limitations for so long as such put options remain out-of-the-money. In the event that the strike price of such a put option returns to being in-the-money, the instrument’s notional amount would again be included in the volume limitations. If the reversal of a prior exclusion results in an over-hedged notional position, we will be required to become compliant with the notional volume limitations within 30 days of the reversal.

Approved Markets. Our risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (“NYMEX”) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. All of our hedge counterparties are also lenders under our revolving credit facility, and the payment obligations in connection with our hedge transactions are secured by a first priority lien on the collateral securing our revolving credit facility indebtedness that ranks equal in right of payment with liens granted in favor of our secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even, if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness. We have not executed any derivative transactions on the NYMEX as of December 31, 2011.

We generally seek, whenever possible, to enter into hedge transactions that meet the requirements for effective hedges as outlined in ASC 815 “Derivatives and Hedging.”

Texas Segment. With the exception of condensate and a portion of our natural gasoline production, NGLs are hedged using the Mont Belvieu index, the same index used to price the underlying commodities. For 2011, we used natural gas call spread options to hedge a portion of our net operational short position resulting from processing at our Houston Central complex. The call spread options are based on the Houston Ship Channel index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas segment because our natural gas position is neutral to short due to our contractual arrangements.

Oklahoma Segment. Historically, we have used options priced on the CenterPoint East index to hedge natural gas in Oklahoma. For 2011, we used a basis swap between the CenterPoint East and the Houston Ship Channel indices to mitigate the basis risk affecting Oklahoma natural gas that we use to offset our short natural gas position in Texas. Currently, the principal indices used to price the underlying commodity for our Oklahoma segment are the ONEOK Gas Transportation index and the CenterPoint East index. While this creates the potential for additional basis risk, statistical analysis reveals that the CenterPoint East index and the ONEOK Gas Transportation index historically have been highly correlated. With the exception of condensate, NGLs are contractually priced using the Conway index, but because there is an extremely limited forward market for Conway-based hedge instruments, we use the Mont Belvieu index for NGL hedges. This creates the potential for basis risk. Historically these indices have been highly correlated; however, these indices displayed greater variability beginning in 2009 that continued throughout 2011. In the fourth quarter of 2011, the basis between the Conway index and the Mont Belvieu index widened to a maximum quarterly average differential of $13.50 per Bbl. At February 17, 2012, this basis differential was $8.76 per Bbl.

 

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Rocky Mountains Segment. Because the profitability of our Rocky Mountains segment is only indirectly affected by the level of commodity prices, this segment has no outstanding transactions to hedge commodity price risk.

Our Hedge Portfolio

Commodity Hedges. As of December 31, 2011, our commodity hedge portfolio totaled $10.8 million in assets. For additional information, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of this report.

Mont Belvieu Purity Ethane Purchased Puts

 

     Put  
     Strike
(Per gallon)
     Volumes
(Bbls/d)
 

2012

   $ 0.5900         1,000   

2012

   $ 0.5900         500   

2012

   $ 0.6700         400   

Mont Belvieu TET Propane Purchased Puts

 

     Put  
     Strike
(Per gallon)
     Volumes
(Bbls/d)
 

2012(1)

   $ 1.1500         700   

2012

   $ 1.0700         600   

2012

   $ 1.1700         600   

2012(1)

   $ 1.3200         400   

2013

   $ 1.2400         600   

2013

   $ 1.2750         350   

2013(2)

   $ 1.2200         300   

2013(2)

   $ 1.2800         300   

 

(1) Instrument not designated as a cash flow hedge under hedge accounting.
(2) Instrument was purchased during the first quarter of 2012.

Mont Belvieu Non-TET Isobutane Purchased Puts

 

     Put  
     Strike
(Per gallon)
     Volumes
(Bbls/d)
 

2012

   $ 1.3900         165   

2012(1)

   $ 1.3900         285   

2013

   $ 1.6000         200   

2013

   $ 1.6800         100   

2013(2)

   $ 1.9000         50   

 

(1) Instrument not designated as a cash flow hedge under hedge accounting.
(2) Instrument was purchased during the first quarter of 2012.

 

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Mont Belvieu Non-TET Normal Butane Purchased Puts

 

     Put  
     Strike
(Per gallon)
     Volumes
(Bbls/d)
 

2012

   $ 1.3500         250   

2012

   $ 1.3600         125   

2012(1)

   $ 1.3600         225   

2012(1)

   $ 1.4600         150   

2013

   $ 1.5800         300   

2013

   $ 1.6500         100   

2013(2)

   $ 1.8000         100   

 

(1) Instrument not designated as a cash flow hedge under hedge accounting.
(2) Instrument was purchased during the first quarter of 2012.

WTI Crude Oil Purchased Puts

 

     Put  
     Strike
(Per Bbl)
     Volumes
(Bbls/d)
 

2012(1)

   $ 79.00         300   

2012

   $ 83.00         500   

2012(1)

   $ 83.00         150   

2012

   $ 85.00         350   

2012

   $ 90.00         200   

2013

   $ 90.00         400   

2013

   $ 99.00         350   

2013(2)

   $ 95.00         100   

2013(1)(2)

   $ 95.00         250   

 

(1) Instrument not designated as a cash flow hedge under hedge accounting.
(2) Instrument was purchased during the first quarter of 2012.

Interest Rates. Our interest rate exposure results from variable rate borrowings under our debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. These activities are governed by our risk management policy, which limits the maturity and notional amounts of our interest rate swaps as well as restricts counterparties to certain lenders under our revolving credit facility. As of December 31, 2011, we were exposed to changes in interest rates as a result of the indebtedness outstanding under our revolving credit facility of $385 million, of which $95 million was hedged with interest rate swaps. Our revolving credit facility had an average floating interest rate of 2.76% as of December 31, 2011 and a 1% increase in interest rates on the amount of debt in excess of the $95 million that was hedged would result in an increase in interest expense and a corresponding decrease in net income of approximately $2.9 million annually.

As of December 31, 2011, the fair value of our interest rate swaps liability totaled $3.6 million. For additional information on our interest rate swaps, please read Note 9, “Financial Instruments,” to our consolidated financial statements included in Item 8 of this report.

Counterparty Risk

We are diligent in attempting to ensure that we provide credit only to credit-worthy customers. However, our purcha