UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

 

 

Commission file number: 001-32329

 

COPANO ENERGY, L.L.C.

(Exact name of registrant as specified in its charter)

 

 

(713) 621-9547

 

(Registrant’s telephone number, including area code)

 

None

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

 

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

 

 

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

 

Title of Class

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 o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     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 o

 

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 o     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of 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.  o

 

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

 

 

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

 

As of June 30, 2009, the aggregate market value of our voting and non-voting common equity held by non-affiliates of the registrant was approximately $812 million based on $16.05 per common unit, the closing price of our common units as reported on The NASDAQ Global Select Market.

 

As of February 19, 2010, 58,002,428 of our common units were outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:

 

 

 

TABLE OF CONTENTS

 

 

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.

 

 

 

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

 

General

 

We are an energy company engaged in the business of providing midstream services to natural gas producers, including natural gas gathering, compression, dehydration, treating, marketing, transportation, processing, conditioning and fractionation services. Our assets are located in Oklahoma, Texas, Wyoming and Louisiana and include approximately 6,400 miles of active natural gas gathering and transmission pipelines and seven natural gas processing plants, with over one Bcf/d of combined processing capacity. In addition to our natural gas pipelines, we operate 256 miles of natural gas liquids (“NGL”) pipelines, and through September 2009, we operated a 59-mile crude oil pipeline.

 

We were formed in August 2001 as a Delaware limited liability company to acquire entities operating under the Copano name since 1992. We completed our initial public offering (“IPO”) of common units representing limited liability company interests on November 15, 2004. 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 under the symbol “CPNO.”

 

Recent Developments

 

Expanded commodity risk management portfolio.  On January 15, 2010, we announced that we expanded our commodity risk management portfolio during the fourth quarter of 2009 and January 2010. We acquired puts for ethane, propane and West Texas Intermediate crude oil, and entered into basis swaps for Houston Ship Channel

Index and Centerpoint East Index natural gas, at strike prices reflecting current market conditions. The new hedges were executed with four investment grade counterparties for a net cost of approximately $7.3 million.

 

North Texas contract.  In February, 2010, we executed a long-term gathering and processing agreement with a large producer, under which we will provide the producer with natural gas gathering and processing services in the north Barnett Shale play in Cooke and Montague Counties, Texas. To accommodate the producer’s anticipated growing natural gas volumes in the area, we plan to expand our Saint Jo processing plant from 50,000 Mcf/d to 100,000 Mcf/d during the third quarter of 2010.

 

Declaration of distribution.  On January 13, 2010, our Board of Directors declared a cash distribution for the three months ended December 31, 2009 of $0.575 per common unit. The distribution, totaling $31.9 million, was paid on February 11, 2010 to all common unitholders of record at the close of business on February 1, 2010. The total distribution for the year ended December 31, 2009 was $2.30 per unit, a 3% increase from $2.235 per unit distributed for the year ended December 31, 2008.

 

Approved capital projects for 2010.  Our board of directors has approved approximately $130 million in expansion capital projects for 2010. Our major areas of focus for 2010 projects are the Eagle Ford Shale and our Houston Central processing plant in south Texas, our Saint Jo processing plant and pipelines in north Texas (including to accommodate anticipated volumes from a large producer, as noted above) and additional pipeline and processing capacity in Oklahoma.

 

Unit conversions.  All of our 3,245,817 Class D units converted into common units on a one-for-one basis on February 11, 2010, the date we paid our cash distribution to common unitholders for the fourth quarter of 2009.

 

Business Strategy

 

Our management team is committed to exploiting new business opportunities associated with our existing assets, pursuing acquisition and organic expansion opportunities, and managing our commodity risk exposure. Key elements of our strategy include:

 

 

In addition, 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.”

 

Our Operations

 

Our natural gas pipelines collect natural gas from wellheads or designated points near producing wells and deliver these volumes to our processing plants, third-party processing plants, third-party pipelines, local distribution companies, power generation facilities and industrial consumers. Our processing plants take delivery of natural gas from our gathering systems as well as third-party pipelines. The natural gas is then treated as needed to remove contaminants and then processed or conditioned to extract mixed NGLs. After treating and processing or conditioning, we deliver the residue gas primarily to third-party pipelines through plant interconnects and sell the NGLs, in some cases after separating the NGLs into select component products, to third parties through our plant interconnects or our NGL pipelines. In addition, through September 2009, we owned and operated a crude oil pipeline.

 

Our Operating Segments

 

Overview

 

We manage and operate our business in three geographic segments: Oklahoma, Texas and Rocky Mountains. Our operating segments are summarized in the following table:

 

Copano Energy Operating Segments

 

 

 

 

For additional disclosure about our segments, please read Note 16, “Segment Information,” to our consolidated financial statements included in Item 8 of this report.

Oklahoma

 

Our Oklahoma segment operates in active natural gas producing areas in central and east Oklahoma and includes assets we acquired through our purchases of Cimmarron Gathering, LP (“Cimmarron”) in May 2007 and ScissorTail Energy, LLC (“ScissorTail”) in August 2005. These assets include:

 

 

The following map represents our Oklahoma segment:

 

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

 

Oklahoma Pipelines

 

 

 

 

Oklahoma Processing

 

 

 

 

In addition to transporting natural gas to our plants, our Oklahoma segment delivers natural gas to five third-party plants for processing. Depending on our contractual arrangements, third-party processors 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 39,428 Mcf/d for the year ended December 31, 2009.

 

Stroud System and Interconnected Area

 

Stroud System.  The Stroud system is located in Payne, Lincoln, Oklahoma, Pottawatomie, Seminole Atoka, Bryan, Coal, Hughes and Okfuskee Counties, Oklahoma. In 2009, we delivered approximately 81% of the average throughput on this system to our Paden plant, and we delivered the remainder to third-party processing plants.

 

Paden Processing Plant.  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 Inc. (a subsidiary of OGE Energy Corp.) or ONEOK Gas Transmission (“OGT”). We deliver NGLs from the Paden plant to ONEOK Hydrocarbon and condensate is trucked by Teppco Partners (“Teppco”).

 

Milfay System and Processing Plant.  The Milfay system is located in Tulsa, Creek, Payne, Lincoln and Okfuskee Counties, Oklahoma. We deliver natural gas gathered on the Milfay system to our Milfay and Paden plants. We deliver the residue gas from the Milfay plant into OGT 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 and Paden plants. We deliver the residue gas from the Glenpool plant into either OGT 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 OGT. Wellhead production on the western portion of the Osage system tends to be richer; we currently deliver the production to Keystone Gas, which delivers it to a third-party processor. We are constructing a 10,000 Mcf/d processing plant on the Osage system. We will begin directing rich gas from the Osage system to our processing plant once it is operational, which we anticipate will be in the second quarter of 2010.

 

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. Wellhead production on the Mountain systems is lean and generally does not require processing. We deliver natural gas from the Mountain systems to, among others, CenterPoint and Enogex.

 

Crude Oil Pipeline.  We sold our only crude oil pipeline in a transaction that was effective October 1, 2009.

 

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 OGT and sell the NGLs to Murphy Energy Corporation 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, 2009, we have made $12.4 million in aggregate capital contributions to Southern Dome and have received an aggregate of $8.4 million in member distributions.

 

Texas

 

Our Texas segment operates in south and north Texas and includes 2,033 miles of natural gas gathering and transmission pipelines, our Houston Central plant, our Saint Jo plant and five NGL pipelines, two of which are leased. Our Texas segment also includes our Lake Charles plant in Lake Charles, Louisiana, which has limited operations.

The following map represents our Texas segment:

 

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

 

Texas Pipelines

 

 

 

 

Texas Processing

 

 

 

 

South Texas

 

South Texas Systems.  We deliver a substantial majority of the natural gas gathered on our systems in south Texas to our Houston Central plant for treating and processing, or conditioning, as needed. Our gathering systems in this area deliver to our Houston Central plant via the Laredo-to-Katy pipeline, a 30-inch diameter natural gas transmission pipeline system owned by Kinder Morgan, which extends along the Texas Gulf Coast from south Texas to Houston.

 

Our south Texas gathering systems that deliver to our Houston Central plant gather natural gas from fields located in Atascosa, Bee, DeWitt, Duval, Goliad, Jim Hogg, Jim Wells, Karnes, Live Oak, Nueces, Refugio, San Patricio and Webb Counties. Some of these systems also deliver to Natural Gas Pipeline Company of America (“NGPL”), DCP Midstream, and Houston Pipe Line Co. (“HPL”) (an affiliate of Energy Transfer Partners), Southcross, Texas Eastern Transmission, Centerpoint and ExxonMobil.

 

Our south Texas systems include the Webb/Duval gathering system, which is owned by Webb Duval, a general partnership that we operate and in which we own a 62.5% interest. We operate the Webb/Duval system subject to the rights of the other partners, including rights to approve capital expenditures in excess of $100,000, financing arrangements by the partnership or any expansion projects associated with this system. In addition, 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.

 

Our Copano Bay gathering system and Encinal Channel pipeline operate onshore and offshore in Aransas, Nueces, Refugio and San Patricio Counties, Texas. These systems gather natural gas offshore in Aransas, Nueces and Copano Bays and from nearby onshore lands. Natural gas, produced water and condensate are separated at our Lamar and Estes Cove separation and dehydration facilities. We deliver any natural gas from the Estes Cove facility to the Lamar facility, which delivers gas to a third party for processing.

 

Houston Central Systems and Processing Plant.  Our Houston Central gathering systems gather natural gas near the Houston Central plant in Colorado, DeWitt, Lavaca, Victoria and Wharton Counties, and deliver the gas to the plant directly, instead of via the Kinder Morgan Laredo-to-Katy pipeline. These systems can also take delivery of natural gas from Enterprise Products Partners and DCP Midstream.

 

Our Houston Central plant has approximately 700,000 Mcf/d of processing capacity and is the second largest processing plant in south Texas. In addition to the conditioning capability described below, the Houston Central plant has:

 

 

We modified the Houston Central plant in 2003 to provide us the ability to process gas only to the extent required to meet downstream pipeline hydrocarbon dew point specifications, which we refer to as conditioning. We installed two new 700 horsepower, electric-driven compressors in 2003 to provide propane refrigeration through the lean oil portion of the plant, which enables us to shut down our steam-driven refrigeration compressor when conditioning natural gas, and we installed a third electric-driven compressor in 2007. Conditioning capability allows us to preserve a greater portion of the value of natural gas when processing is not economic because it allows us to:

 

 

When we elect to condition natural gas, typically our natural gas fuel consumption volumes are reduced by approximately 70%, while our average NGLs extracted are reduced by approximately 91%.

 

At the Houston Central plant, we process or condition natural gas delivered by the Kinder Morgan Laredo-to-Katy pipeline, which the plant straddles, and our Houston Central gathering systems. The plant has tailgate interconnects with Kinder Morgan, HPL, Tennessee Gas Pipeline Company and Texas Eastern Transmission for redelivery of residue natural gas. In addition, we operate four NGL pipelines at the tailgate of the plant. Teppco 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.

 

Sheridan, Brenham, Markham and KS NGL Pipelines.  The west portion of the Sheridan NGL pipeline originates at the tailgate of the Houston Central plant. We plan to begin using the Sheridan NGL line for delivery of purity propane beginning late in the first quarter of 2010. The Sheridan NGL line can also be used for delivery of NGLs into Enterprise Products Partners’ Seminole Pipeline on the west side of Houston. The east portion of the Sheridan NGL pipeline originates at the Enterprise Products Partners’ Almeda station in south Houston and delivers butylenes to the Shell Deer Park plant on the Houston Ship Channel.

 

The Brenham NGL pipeline originates at the tailgate of our Houston Central plant and provides us the option of delivering NGLs into Enterprise Products Partners’ Seminole pipeline near Brenham, Texas. We lease the Brenham NGL pipeline from Kinder Morgan under a 5-year lease agreement that expires in February 2011.

 

We acquired the Markham pipeline in December 2008 and placed it into service for delivery of NGLs to DCP Midstream beginning in August 2009. We are expanding the deethanizer at our Houston Central plant and plan to convert this line into a purity ethane pipeline, which we expect to place into service late in the first quarter of 2010.

 

We leased the KS NGL line from Dow Hydrocarbon and Resources in January 2010. The KS NGL pipeline originates in Waller County and extends southeast for approximately 51 miles to Brazoria County. This line will interconnect with the Sheridan NGL pipeline and will be used to deliver purity propane.

 

Our Commercial Relationship with Kinder Morgan.  Kinder Morgan owns a 2,500-mile natural gas pipeline system that extends along the Texas Gulf Coast from south Texas to Houston and primarily serves utility and industrial customers in the Houston, Beaumont and Port Arthur areas. Kinder Morgan sells and transports natural gas, and we use Kinder Morgan as a transporter because our Houston Central plant straddles its 30-inch-diameter Kinder Morgan Laredo-to-Katy pipeline. Using Kinder Morgan as a transporter allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central plant and downstream markets. Kinder Morgan’s pipeline also delivers to our Houston Central plant natural gas for its own account, which we refer to as “KMTP Gas.” Under our contractual arrangements relating to KMTP Gas, we receive natural gas at our plant, process or condition it and sell the NGLs to third parties at market prices. For a discussion of our agreements with Kinder Morgan, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Our Contracts.”

 

Upper Gulf Coast Systems

 

Our Upper Gulf Coast systems are used for gathering, transportation and sales of natural gas to the north of Houston, Texas, in Houston, Walker, Grimes, Montgomery and Harris Counties. In addition to gas we gather, we receive natural gas from interconnects with HPL, Kinder Morgan Texas, Tennessee Gas Pipeline’s north zone delivery meter, Atmos Pipeline — Texas and Enbridge Pipelines (East Texas) and Texas Eastern Transmission. We deliver the natural gas gathered or transported on these systems to multiple CenterPoint Energy city gates in Montgomery and Walker Counties, to Universal Natural Gas and Entergy’s Lewis Creek generating plant, and to several industrial consumers.

North Texas Systems

 

Our pipelines in north Texas gather natural gas from the Barnett Shale play in Cooke, Denton, Grayson, Montague and Wise Counties. We deliver natural gas gathered in north Texas to our Saint Jo processing plant in Montague County, Texas, and to third-party processing plants and pipelines. Our systems in north Texas have interconnects with Targa Resources, Atlas Pipeline, SemGas, Atmos and NGPL. We constructed our Saint Jo plant, a cryogenic turbo expander processing plant, to address anticipated drilling activity and provide additional delivery points to producers in north Texas, and placed it in service in September 2009. The Saint Jo plant is currently configured for inlet capacity of 50,000 Mcf/d but will be expanded to a capacity of 100,000 Mcf/d during the third quarter of 2010. The Saint Jo plant includes a 1,200 GPM amine treating facility and condensate stabilization facilities and also has conditioning capability. Our Saint Jo NGL pipeline transports NGLs from the plant to ONEOK’s Arbuckle NGL pipeline.

 

Rocky Mountains

 

Our Rocky Mountains segment operates in coal-bed methane producing areas in Wyoming’s Powder River Basin. We acquired the business and assets in this segment through our purchase of Denver-based Cantera in October 2007. Our Rocky Mountains assets consist primarily of a 51.0% managing membership interest in Bighorn, a 37.04% managing membership interest in Fort Union, two firm gathering agreements with Fort Union and two firm capacity transportation agreements with Wyoming Interstate Gas Company (“WIC”). Two subsidiaries of ONEOK Partners own the remaining 49% membership interests in Bighorn, and subsidiaries of Anadarko, Williams, and ONEOK Partners own the remaining 62.96% membership interests in Fort Union. Bighorn and Fort Union operate natural gas gathering systems in the Powder River Basin.

 

Rocky Mountains Pipelines and Services⁽¹⁾

 

 

 

 

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

 

Bighorn Gathering System

 

The Bighorn gas gathering system is located in Johnson, Sheridan and Campbell Counties, Wyoming. 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.

 

Although we serve as manager and field operator of Bighorn, certain significant business decisions with respect to Bighorn require the majority or unanimous approval of a management committee to which we have the right to appoint 50% of the committee members. Examples include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, the determination of excess cash for mandatory distribution to members, dispositions of assets or entry into new gathering agreements or amendments to existing gathering agreements, among others.

 

Fort Union Gathering System

 

The Fort Union gas gathering system is located in Campbell and Converse Counties, Wyoming. Fort Union takes high-pressure delivery of gas from the Bighorn system and also provides high pressure gas gathering services to producers that deliver gas directly or indirectly into the Fort Union system. Natural gas gathered from these producers is relatively high in carbon dioxide and, accordingly, must be treated at Fort Union’s Medicine Bow amine 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 gathers a majority of the gas across its system under standard firm gathering agreements between Fort Union and each of its four owners, including us. Pursuant to these 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 whether the owner uses the capacity. 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 if used. To the extent an owner does not use its allocated capacity or market it to third parties, the capacity is available for use by the other owners. Any capacity not used by the owners or marketed to third parties 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, 32% of Fort Union’s total firm capacity is demand capacity. The firm gathering agreements between Fort Union and its owners terminate only upon mutual agreement of the parties.

 

Although we serve as the managing member of Fort Union, we do not operate the Fort Union system, nor do we provide certain administrative services. The Anadarko subsidiary acts as field operator and conducts all construction and field operations, while the ONEOK Partners subsidiary acts as administrative manager and provides gas control, contracts management and contract invoicing services. As managing member of Fort Union, we perform all other acts incidental to the management of Fort Union’s business, including determining distributions to owners, executing gathering agreements, approving certain capital expenditures and monitoring the performance of the field operator and administrative manager, subject to the requirement that certain significant business decisions receive the 65% or unanimous approval of the owners. Examples include decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the owners’ firm gathering agreements, among others.

 

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 (which expire only upon mutual agreement of the parties) currently provide us with total capacity of 387,102 Mcf/d consisting of demand capacity of 75,000 Mcf/d and variable capacity of up to 312,102 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 an additional five-year term. We have capacity release agreements with producers in the Powder River Basin, under which they pay for the right to use our WIC capacity. These capacity release agreements cover all of our long-term WIC capacity and continue through 2019. We are obligated to pay for our capacity on WIC’s Medicine Bow lateral regardless of whether we use the capacity. Even if we release capacity to a third party, we would remain subject to credit risk, as we would be obligated to pay for the capacity if the third party failed to pay.

 

Natural Gas Supply

 

We continually seek new supplies of natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. We obtain new natural gas supplies in our operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage or by obtaining natural gas supplies that were previously gathered on third-party gathering systems. We contract for supplies of natural gas from producers under a variety of contractual arrangements. The primary term of each contract varies significantly, ranging from one month to the life of the dedicated reserves. The terms of our natural gas supply contracts vary depending on, among other things, gas quality, pressure of natural gas produced relative to downstream pressure requirements, competitive environment at the time the contract is executed and customer requirements. For a summary of our most common contractual arrangements, please read Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Our Contracts.”

 

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 or the anticipated life of producing reserves, and volumes of natural gas transported on our pipeline systems in the future could be less than we anticipate. This may cause our revenues and operating income to be less than we expect. 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 2009, we saw decreases in natural gas and NGL prices and constrained capital and credit markets due to the prevailing economic uncertainty, and we experienced a resulting decline in drilling activity in each of our operating areas. Although commodity prices and financial market conditions have continued to recover, improvements in drilling activity remain sporadic, and it remains unclear when producers will undertake sustained increases in drilling activity throughout the areas in which we operate. Lower drilling levels over a sustained period would have a negative effect on the volumes of natural gas volumes we gather and process. 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 volumes 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.

 

For additional information, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Trends and Uncertainties — Commodity Prices and Producer Activity.”

 

Oklahoma

 

Pursuant to a contract that extends through mid-year 2020, our largest Oklahoma producer by volume has dedicated to us all of its production within a 1.1 million acre area. We also have dedications from other producers covering their production within an aggregate 572,800 acres pursuant to contracts ending between 2014 and 2016.

During the year ended December 31, 2009, our Oklahoma segments’ top producers by volume of natural gas were New Dominion, Altex Resources, Special Energy Corporation, Antero Resources and Northeast Shelf Energy LLC (CEP Mid-Continent, LLC), which collectively accounted for approximately 65% of the natural gas delivered to our Oklahoma systems during the period.

 

Texas

 

During the year ended December 31, 2009, our top producers by volume of natural gas were Upstream Energy, Rosetta Resources, EOG Resources, XTO Energy and DCP Midstream, which collectively accounted for approximately 38% of the natural gas delivered to our Texas systems during the period.

 

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 Converse, Campbell and Johnson Counties, Wyoming. Under the AMI, the owners have 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 firm capacity rights.

 

During the year ended December 31, 2009, Fort Union’s top three shippers based on gathering fees accounted for approximately 81% of Fort Union’s revenue.

 

The owners of Bighorn have established an approximately 3.8 million-acre AMI within the Powder River Basin of northern Wyoming and southern Montana, 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 one million acres of land within the Powder River Basin has been dedicated to the Bighorn Gathering system by producers. Bighorn’s largest Rocky Mountains producer by volume has dedicated to Bighorn approximately 300,000 acres pursuant to a contract that extends through 2019. Bighorn also has dedications from other producers within the same dedicated area pursuant to contracts ending primarily between 2011 and 2019.

 

During the year ended December 31, 2009, Bighorn’s top two producers based on gathering fees collectively accounted for approximately 82% Bighorn’s revenue.

 

Competition

 

The midstream natural gas 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 and processing. We believe that offering an integrated package of services, while remaining flexible in the types of contractual arrangements, allows us to compete more effectively for new natural gas supplies in our operating regions.

 

We face strong competition in acquiring new natural gas supplies and in pursuing acquisition opportunities as part of our long-term growth strategy. Our competitors include major interstate and intrastate pipelines, other natural gas gatherers and natural gas producers that gather, process and market natural gas. Our competitors may have capital resources and control supplies of natural gas greater than ours.

 

Oklahoma

 

We provide comprehensive services to natural gas producers in our Oklahoma segment, including gathering, transportation, compression, dehydration, treating and 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.

 

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 compression facilities, 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 and Enerfin.

 

Texas

 

We provide comprehensive services to natural gas producers in our Texas segment, including gathering, transportation, compression, dehydration, treating, conditioning and processing, and, beginning in 2010, NGL fractionation. 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. In addition, using centralized treating and processing facilities, we can in most cases attach producers that require these services more quickly and at a lower initial capital cost than our competitors, due in part to the elimination of some field equipment and greater economies of scale at our Houston Central plant. For natural gas that exceeds the maximum carbon dioxide and NGL specifications for interconnecting pipelines and downstream markets, we believe that we offer treating, conditioning and other processing services on competitive terms.

 

Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, Lobo Pipeline Company (an affiliate of ConocoPhillips), Kinder Morgan, DCP Midstream, Southcross Energy, HPL, ExxonMobil, Targa Resources, Atlas Pipeline, Devon Energy and Regency.

 

Rocky Mountains

 

A significant portion of the gas on the Bighorn system is dedicated to Bighorn under long-term gas gathering agreements and, accordingly, is not available to competitors. Additionally, Fort Union’s centralized amine treating facility provides Fort Union with a competitive advantage.

 

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, Western Gas Resources and by late 2010, Bison Pipeline.

 

Industry Overview

 

The midstream natural 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 natural gas gathering, compression, dehydration, treating, conditioning, processing, transportation and fractionation, see diagram of the industry below.

 

 

 

 

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.

 

 

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. 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 Intrastate 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”), 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. Compliance with these regulations has not affected us materially. FERC also requires certain major non-interstate natural gas pipelines to post, on a daily basis, capacity and scheduled flow information under regulations that become effective July 1, 2010. We are evaluating FERC’s final order to determine whether our operations will be subject to its daily posting requirements, which could subject us to additional costs and administrative burdens. These regulations are currently pending review before the United States Court of Appeals for the 5^th Circuit, and we cannot predict how the results of such judicial review might affect their applicability to us.

 

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 unchanged.

 

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, or have been 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, Health and Safety Matters

 

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

 

 

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. Certain environmental statutes impose strict and, under certain circumstances, joint and several liability for costs required to clean up and restore sites where wastes or other regulated substances 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.

 

We believe that our operations are in substantial compliance with applicable environmental laws and regulations and that compliance with existing federal, state and local environmental laws and regulations will not have a material adverse effect on our business, financial position or results of operations. 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, health and safety laws and regulations to which our business operations are subject:

 

Hazardous Waste.  Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many crude oil and natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development or production of crude oil and natural gas. However, these oil and gas exploration and production wastes may still be regulated under state law or the solid waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils may be regulated as hazardous waste. The transportation of crude oil or natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements.

Site Remediation.  The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“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 U.S. Environmental Protection Agency (“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 may 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. In fact, there is evidence that petroleum hydrocarbon spills or releases have occurred at some of the properties owned or leased by us. In addition, some of these properties have been operated by third parties or by previous owners 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, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination. As of December 31, 2009, 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, as amended and comparable state laws and regulations. These laws and regulations regulate 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, or use specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. We likely will 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 believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies.

 

Water Discharges.  Our operations are subject to the Federal Water Pollution Control Act, as amended, 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.

 

Pipeline Safety.  Our pipelines are subject to regulation by the U.S. Department of Transportation (“DOT”), under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”) and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), pursuant to which the DOT has established requirements relating to

the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The NGPSA covers the pipeline transportation of natural gas and other gases and the transportation and storage of liquefied natural gas, whereas the HLPSA covers the pipeline transportation of hazardous liquids, including crude oil, NGLs and petroleum products. Under both federal acts, any entity that owns or operates covered pipeline facilities is required to comply with the regulations under the NGPSA and HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with NGPSA and HLPSA requirements.

 

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, has established a series of rules which require pipeline operators to develop and implement integrity management programs for natural gas pipelines located in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Similar rules are also in place for operators of hazardous liquid pipelines. In addition, pursuant to authorization granted by PIPES, the DOT issued final rules in June 2008 that amends its pipeline safety regulations to extend regulatory coverage 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. The safety requirements imposed by the final rule address primarily pipeline corrosion and third-party damage concerns but do not include pipeline integrity management criteria. Also, the TRRC and the OCC have adopted regulations similar to existing DOT regulations for intrastate natural gas gathering and transmission lines while the Wyoming Public Service Commission has done the same only with respect to intrastate natural gas gathering and transmission lines. Current compliance with these existing federal and state rules has not had a material adverse effect on our operations.

 

Employee Health and Safety.  We are subject to the requirements of the federal Occupational Safety and Health Act, as amended (“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.

 

Anti-terrorism Measures.  The federal Department of Homeland Security Appropriations Act of 2007 requires the Department of Homeland Security (“DHS”), to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present “high levels of security risk.” The DHS issued an interim final rule in April 2007 regarding risk-based performance standards to be attained pursuant to the act and, on November 20, 2007, further issued an Appendix A to the interim rules that establish chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Based on information supplied by us to the DHS, the agency has determined that our facilities do not present high levels of security risk; therefore, we are in compliance with the existing interim rules.

 

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, the U.S. Fish and Wildlife Service (“USFW”) is currently evaluating whether the sage grouse, a ground-dwelling bird that inhabits portions of the Rocky Mountain region including Wyoming, where we have natural gas gathering system operations, requires protection as an endangered species under the ESA. The USFW is expected to render a determination on protection of the sage grouse in 2010. An Endangered Species Act designation could result in broad conservation measures restricting or even prohibiting natural gas exploration and production activities in affected areas as well as impose restrictions on expansion of our natural gas gathering systems. Any curtailment in exploration and production activities by operators from whom we gather natural gas could have

an adverse effect on our natural gas gathering services. Moreover, the federal Bureau of Land Management and the State of Wyoming are pursuing separate strategies to maintain and enhance sage grouse habitat, which could have an adverse effect on natural gas production and gathering activities in affected areas.

 

Climate Change.  Certain scientific studies suggest that emissions of certain gases, commonly referred to as “greenhouse gases” (“GHGs”) and including carbon dioxide and methane, may be contributing to the warming of the Earth’s atmosphere and other climatic changes. On June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs that may contribute to the warming of the Earth’s atmosphere and other climatic changes. ACESA would require a 17 percent reduction in GHG emissions from 2005 levels by 2020 and just over an 80 percent reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances to certain major sources of GHG emissions so that such sources could continue to emit GHGs into the atmosphere. These allowances would be expected to escalate significantly in cost over time. The net effect of ACESA would be to impose increasing costs on the combustion of carbon-based fuels such as refined petroleum products, oil and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the current Administration has indicated its support of legislation to reduce GHG emissions through an emission allowance system. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, primarily through the planned development of emission inventories or regional GHG cap and trade programs. These cap and trade programs could require major sources of emissions, such as electric power plants, or major producers of fuels or NGL products, such as petroleum refineries or NGL fractionators, to acquire and surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for GHG emissions resulting from our operations (e.g., compressor stations) or from NGLs we fractionate.

 

Also, on December 15, 2009, the EPA published its findings that emissions of GHGs constitute an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has already proposed two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including NGL fractionation plants, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. The adoption and implementation of any federal, regional or state laws or regulations limiting emissions of GHGs in the U.S. could adversely affect the demand for our midstream services or require us to incur costs to reduce emissions of GHGs associated with our operations.

 

Office Facilities

 

We occupy approximately 31,000 square feet of space at our executive offices in Houston, Texas under a lease expiring on May 31, 2012. At the expiration of the primary term, we have an option to renew this lease for an additional five years at then-prevailing market rates. We also occupy approximately 26,000 square feet of office space in Tulsa, Oklahoma, which serves as the administrative offices for our Oklahoma employees. The Tulsa lease expires December 31, 2015 but provides us with an option to terminate in December 2013. We occupy approximately 6,000 square feet of space in Englewood, Colorado, which serves as the administrative offices for our Rocky Mountains employees. The Englewood lease expires October 31, 2013 and provides us with two consecutive five-year renewal options at then-prevailing market rates. We also lease property or facilities for some of our field offices. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet our needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed.

 

Employees

 

As of December 31, 2009, we, through our subsidiaries, CPNO Services, L.P. and ScissorTail, had 325 full-time employees and 6 part-time employees, and Copano/Operations, Inc. (“Copano Operations”) employed 12 full-time employees and 2 part-time employees for our benefit. We were required to reimburse Copano Operations for

its costs and expenses incurred in providing operating and administrative services to us, including the services of its employees. Beginning January 1, 2010, we modified our relationship with Copano Operations and hired the majority of Copano Operations’ employees who provided services to us. For more information concerning our arrangement with Copano Operations, please read Note 9, “Related Party Transactions,” to our consolidated financial statements included in Item 8 of this report. 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 Internet website (http://www.copanoenergy.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.

 

 

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 operation 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 available cash each quarter to pay distributions at the current level. Under the terms of our limited liability company agreement, we must set aside any cash reserve amounts before making a distribution to our unitholders. The amount of cash we can distribute principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

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

 

 

 

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

 

A decrease in our cash flow will reduce the amount of cash we have available for distribution to our unitholders.

 

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves, and is not solely a function of profitability, 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.

 

Our cash flow and profitability depend upon prices and market demand for natural gas and NGLs, which are beyond our control and have been 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 continue. For example, on July 2, 2008, natural gas prices were $13.32 per MMBtu at the Henry Hub in Louisiana, which serves as the pricing point for natural gas futures contracts traded on the New York Mercantile Exchange (“NYMEX”). They subsequently declined sharply, reaching a low of $1.85 per MMBtu at Henry Hub in September, 2009. As of February 18, 2010, the closing price of natural gas at the Henry Hub was $5.48 per MMBtu. Based on average monthly Mt. Belvieu prices and our weighted-average product mix in Texas for 2009, NGL prices in 2009 ranged from a high of approximately $46.97 per barrel to a low of approximately $25.29 per barrel.

 

We derive a majority 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:

 

 

 

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 fluctuations in commodity prices and interest rates and may reduce our cash flow and subject our earnings to increased volatility.”

 

We may not be able to fully execute our business strategy if we encounter illiquid capital markets.

 

Our business strategy contemplates pursuing acquisitions and capital projects, both in our existing areas of operations and in new regions where we believe growth opportunities are attractive and our business strategies could be applied. We regularly consider and enter into discussions regarding strategic transactions or projects 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. Any limitations on our access to capital will impair our ability to execute our growth strategy. If the cost of capital becomes too expensive, our ability to develop or acquire accretive assets will be limited. We may not be able to raise the necessary funds on satisfactory terms, if at all. The primary factors that influence our cost of capital include market conditions and offering or borrowing costs such as interest rates or underwriting discounts.

 

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.

 

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

 

We have substantial indebtedness. As of February 19, 2010 and in addition to liabilities related to our risk management activities, we had total indebtedness of $872 million, including our senior unsecured notes and our revolving credit facility, and available borrowing capacity under our revolving credit facility was approximately $102 million. Subject to the restrictions governing our existing indebtedness and other financial obligations, 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:

 

 

If we are unable to meet our debt service and other financial obligations, 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.

 

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

 

The indenture governing our outstanding senior unsecured notes contains various covenants that limit our ability and the ability of specified subsidiaries to, among other things:

 

 

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 and the ability of our subsidiaries to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or conduct operations.

 

If we are unable to comply with our debt covenants, we could be forced to restructure or refinance our debt on less favorable terms; otherwise, our failure to comply could result in defaults under our debt agreements and 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.

 

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 operate in a capital-intensive industry and 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. Specifically, we would be unable to obtain adequate funding under our revolving credit facility if:

 

 

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 capital projects or other business opportunities, which could have a material adverse effect on our results of operations and financial condition.

 

Our ability to obtain financing from sources other than our revolving credit facility is subject to conditions in the credit and capital markets.

 

If we need to raise capital from a source other than our revolving credit facility, we cannot be certain that additional capital will be available to the extent required and on acceptable terms. Global market and economic conditions have been volatile, and the timing and sustainability of an economic recovery remain uncertain. 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 are likely to result in higher interest rates and deterioration in the availability and cost of debt and equity financing.

 

If capital on acceptable terms is unavailable to us, we may be unable to fully execute our growth strategy, otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operations and financial condition.

 

We are exposed to the credit risk of our customers and other counterparties, and 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. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity, all of which are subject to adverse changes in commodity prices and economic and market conditions. Since the most recent economic downturn, 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 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.

 

Our hedging activities do not eliminate our exposure to fluctuations in commodity prices and interest rates 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 natural gas and NGL supply or requirements. 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.

 

Even though monitored by management, our hedging activities may fail to protect us and could reduce our cash flow and profitability. Our hedging activity may be ineffective or adversely affect our cash flow and liquidity, our earnings or both because, among other factors:

 

 

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.

 

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

 

Congress currently is considering broad financial regulatory reform legislation that among other things would impose comprehensive regulation on the over-the-counter (“OTC”) derivatives marketplace and could affect the use of derivatives in hedging transactions. The financial regulatory reform bill adopted by the House of Representatives on December 11, 2009, would subject swap dealers and “major swap participants” to substantial supervision and regulation, including capital and margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally would be someone other than a dealer who maintains a “substantial” net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. The House-passed bill also would provide the CFTC with express authority to impose position limits for OTC derivatives related to energy commodities. Separately, in late January 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona

fide hedging of commercial risks. It is not possible to predict whether or when Congress will act on derivatives legislation or how the CFTC will finalize its proposed regulations, but any laws or regulations that subject us to additional capital or margin requirements or additional restrictions relating to our commodity positions could limit our flexibility in hedging risks associated with our business or increase the costs of our hedging activity.

 

Because of the natural decline in production from existing wells in our operating regions, our future success depends on our ability to continually obtain new sources of natural gas supply, which depends in part on certain factors beyond our control. Any decrease in supplies of natural gas could adversely affect our revenues and operating income.

 

Our gathering and transmission pipeline systems are connected to 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 at our processing plants, we must continually connect new supplies of natural gas and attract new customers to our gathering and transmission lines. 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 for the attachment of such additional volumes to our systems.

 

Fluctuations in energy prices can greatly affect drilling and production rates and investments by third parties in the development of new natural gas reserves. Drilling activity generally decreases as natural gas 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, rig availability, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital.

 

During 2009, we saw decreases in natural gas and NGL prices and constrained capital and credit markets due to the prevailing economic uncertainty, and we experienced a resulting decline in drilling activity in each of our operating areas. Lower drilling levels over a sustained period would have a negative effect on the volumes of natural gas we gather and process. We cannot use hedging to offset the potential effects of declining volumes.

 

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, pricing arrangements, reputation, efficiency, flexibility and reliability. Our major competitors for natural gas supplies and markets in our Texas segment include Enterprise Products Partners, Lobo Pipeline Company, Kinder Morgan, DCP Midstream, Southcross Energy, ExxonMobil, HPL, Targa Resources, Atlas Pipeline, Regency and Devon Energy. The primary competitors in our Oklahoma segment include CenterPoint Field Services, DCP Midstream, ONEOK Field Services, Enogex, Enerfin, Atlas Pipeline, Hiland Partners and MarkWest. The primary competitors in our Rocky Mountains segment include Thunder Creek Gas Gathering, Bitter Creek Pipeline Company, Bear Paw Energy, Western Gas Resources and by late 2010, Bison Pipeline. A number of our competitors are larger organizations than we are.

 

If we are unable to maintain or increase the throughput on our pipeline systems because of decreased drilling activity, decreased production from the wells connected to our systems or inability to connect new supplies of gas and attract new customers to our gathering and transmission lines, then our business, financial results and our ability to achieve our growth strategy could be materially adversely affected.

 

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 contract for natural gas supplies in the Texas region will often depend on our ability to deliver gas to our Houston Central plant and downstream markets, and we rely on Kinder Morgan’s Laredo-to-Katy pipeline to transport natural gas from our south Texas systems to the Houston Central plant. For the year ended December 31, 2009, approximately 49% of the total natural gas delivered by our Texas segment was delivered to Kinder Morgan,

and approximately 80% of the natural gas volumes processed or conditioned at our Houston Central plant was delivered to the plant through the Kinder Morgan Laredo-to-Katy pipeline.

 

If Kinder Morgan’s pipeline were to become unavailable for any reason, the volumes transported to our Houston Central plant would be reduced substantially, and our revenues and operating income from our Texas processing business would be adversely affected. In addition, much of the natural gas we gather in south Texas contains NGLs that must be removed in order to meet downstream market quality specifications. If we were unable to ship such natural gas to our Houston Central plant, we would need to arrange for an alternate means of removing NGLs and transport through other pipelines. Alternatively, we might be required to lease smaller treating and processing facilities so that we could treat and condition or process natural gas as needed to meet pipeline quality specifications.

 

We rely on ONEOK Hydrocarbon to take delivery of NGLs from several of our processing plants, and 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, and natural disasters and operational, mechanical or other hazards. For example, we believe that NGL fractionation facilities on which we depend are subject to increasing capacity constraints due to higher NGL prices and the completion of projects increasing NGL output. Also, some third-party pipelines have minimum gas quality specifications that at times may limit or eliminate our transportation options. Because we do not own or operate Kinder Morgan’s, ONEOK Hydrocarbon’s, or any of these other pipelines and facilities, their continuing operation or availability is not within our control.

 

If any of these pipelines and other facilities becomes unavailable or limited in its ability to provide services on which we depend, our revenues and cash flow could be adversely affected. We would likely incur higher fees or other costs in arranging for alternatives. A prolonged interruption or reduction of service on Kinder Morgan, ONEOK Hydrocarbon or another pipeline or facility on which we depend could hinder our ability to contract for additional gas supplies.

 

To the extent that we make acquisitions in the future and our acquisitions do not perform as expected, our future 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 assimilate our acquisitions could adversely affect our financial condition and results of operations.

 

Our acquisitions potentially involve numerous risks, including:

 

 

 

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 could impair our ability to comply with financial covenants under our debt agreements, 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. Our capitalization and results of operations may change significantly following an acquisition, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

 

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.

 

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 the unwillingness of producers 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 the reserves connected to our pipeline systems is less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas transported on our pipelines in the future could be less than we anticipate. A decline in the volumes of natural gas transported on our pipeline systems may 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.

 

Expanding our business by constructing new assets will subject us to risks that projects may not be completed on schedule, the costs associated with the projects may exceed our expectations and additional natural gas supplies may not be available following completion of the projects, which could cause our revenues to be less than anticipated. Our operating cash flows from our capital projects may not be immediate.

 

One of the ways we may grow our business is by constructing additions or modifications to our existing gathering and transportation systems (including additional compression) and natural gas processing plants. We may also construct new facilities, either near our existing operations or in new areas. Construction of additions or modifications to our existing facilities, and of new facilities, involves numerous regulatory, environmental, political, legal and operational uncertainties beyond our control and requires significant amounts of capital. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and

the availability of required resources. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, we may not receive any material increase in operating cash flow from a project for some time, particularly in the case of greenfield projects. If we experience unanticipated or extended delays in generating operating cash flow from these projects, then we may need to reduce or reprioritize our capital budget in order to meet our capital requirements. We often rely on estimates of future production in deciding to construct additions to our gathering and transportation systems. These estimates may prove to be inaccurate because of the numerous technological, economic and other uncertainties inherent in estimating quantities of future production. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, and that in turn, could adversely affect our cash flows and results of operations.

 

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. The NGA leaves any economic regulation of natural gas gathering to the states. Texas, Oklahoma and Wyoming, the states in which our pipeline facilities are located, do not currently regulate non-utility gathering fees.

 

Our gathering fees and our terms and conditions of service may nonetheless be constrained through state anti-discrimination laws. The states in which we operate have adopted complaint-based regulation of natural gas gathering activities. Natural gas producers, shippers and other affected parties may file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and discrimination with regard to rates and terms of service. A successful complaint, or new laws or regulatory rulings related to gathering or downstream quality specifications, could increase our costs or require us to alter our gathering charges, and our business, and therefore, results of operations and financial condition could be adversely affected. Other state laws and regulations may not 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.

 

Our intrastate natural gas transmission pipeline and several of our gathering systems in Texas are subject to regulation as gas utilities by the TRRC. The TRRC’s jurisdiction over these pipelines extends to both rates and pipeline safety. The rates we charge for transportation services in Texas generally are deemed just and reasonable under Texas law unless challenged in a complaint. A successful complaint, or new state laws or regulatory rulings related to natural gas utilities, could increase our costs or require us to alter our service charges.

 

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 Natural Gas Policy Act of 1978. Section 311 requires, among other things, that rates for such interstate service, which may be established by FERC or the applicable state agency, be “fair and equitable,” and permits the FERC to approve terms and conditions of service. 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.

 

We have interests in NGL pipelines, all of which are located in Texas. We believe that these pipelines do not provide interstate service and that they are thus not subject to FERC jurisdiction under 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. Any of the foregoing could adversely affect our business, revenues and cash flow. The price at which we buy and sell natural gas and NGLs is

currently not subject to federal regulation and, for the most part, is not subject to state regulation. However, with regard to our physical purchases and sales of these energy commodities, our gathering or transportation of these energy commodities, and any related hedging activities that we undertake, we are required to observe 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.

 

The FERC has also promulgated additional market-monitoring and reporting regulations intended to increase the transparency of wholesale energy markets, protect the integrity of such markets and improve the FERC’s ability to assess market forces and detect market manipulation. One such set of regulations, FERC Order No. 720, requires certain major non-interstate pipelines to post daily information on each such pipeline’s internet web site concerning capacity and scheduled flow information. The implementation date of Order No. 720 is July 1, 2010. The FERC has also approved Order No 714, which increases the frequency, level of detail and mode of contract reporting by intrastate Section 311 natural gas pipelines. Additionally, the FERC has imposed new rules requiring certain wholesale purchasers and sellers of physical natural gas to report aggregated annual volume and other information beginning in 2009. These and other transparency rules may subject certain of our operations to additional reporting requirements, which could subject us to further costs and administrative burdens.

 

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, on February 19, 2008, the U.S. Supreme Court agreed to hear arguments in a lawsuit filed by the State of Montana against Wyoming over water rights in two rivers that flow through both states. Montana is asserting that Wyoming is using 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. 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 impacts on the natural gas production in affected areas of Wyoming and, correspondingly, on gathering services that Bighorn and Fort Union provide.

 

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

 

On December 15, 2009, the U.S. EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. Also, on June 26, 2009, the U.S. House of Representatives passed the “American Clean Energy and Security Act of 2009,” or “ACESA,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of GHGs, including carbon dioxide and methane. ACESA would require a 17% reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the

combustion of carbon-based fuels such as oil, refined petroleum products, and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the current Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations or could adversely affect demand for the natural gas and other hydrocarbon products that we produce.

 

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

 

In recently published interpretative guidance on climate change disclosures, the U.S. Securities and Exchange Commission indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our operations could be adversely affected. Potential adverse effects could include damage to our facilities from severe weather such as powerful winds or rising waters in low-lying areas, disruption of our operations, either because of climate-related damage to our facilities or scale-backs in our operations due to the threat of such effects, and higher operating costs and less efficient or non-routine operating practices necessitated by potential climatic effects or in the aftermath of such effects. Significant physical effects of climate change could also affect us indirectly by disrupting natural gas and NGL production in our operating areas, and by disrupting services or supplies provided by service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the costs that may result from potential physical effects of climate change.

 

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 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.

The distinction between FERC-regulated common carriage of NGLs, and the non-jurisdictional intrastate transportation of NGLs, has also been the subject of litigation. The FERC, under the ICA, the Energy Policy Act of 1992 and the rules and orders promulgated thereunder, regulates the tariff rates for interstate NGL transportation and these rates must be filed with the FERC. Under the ICA, tariffs must be just and reasonable and not unduly discriminatory or confer any undue preference. To the extent any of our NGL assets are subject to the jurisdiction of the FERC, 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.

 

We may incur significant costs and liabilities resulting from pipeline integrity programs and related repairs.

 

We are subject to regulation by the DOT under the Natural Gas Pipeline Safety Act of 1968, as amended, with respect to our natural gas lines and the Hazardous Liquids Pipeline Safety Act of 1979, as amended, with respect to 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. In addition, we are subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the PIPES, and pursuant to which the DOT has implemented regulations establishing mandatory inspections for all United States oil (including NGL) and natural gas transportation pipelines and gathering lines meeting certain operational risk and location requirements. Moreover, the DOT has developed PIPES regulations that require operators of certain rural onshore hazardous liquid gathering lines and low-stress pipelines located in specified unusually sensitive areas to comply with additional safety requirements addressing primarily corrosion and third-party damage concerns applicable to such pipelines.

 

Although many of our natural gas facilities fall within a class that is not subject to these requirements, we may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with non-exempt pipelines. Such costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such repairs. Additionally, we may be affected by the testing, maintenance and repair of pipeline facilities downstream from our own facilities. Our NGL pipelines are also subject to integrity management and other safety regulations imposed by the TRRC.

 

Any regulatory expansion of the existing pipeline safety requirements or the adoption of new pipeline safety requirements could also increase our cost of operation and impair our ability to provide service during the period in which assessments and repairs take place, adversely affecting our business.

 

Because we handle natural gas, NGLs and other hydrocarbons in our pipeline and processing businesses, we may incur significant costs and liabilities in the future resulting from a failure to comply with new or existing environmental regulations or an accidental release of waste substances into the environment.

 

The operation of our gathering systems, plants and other facilities is subject to stringent and complex federal, state and local environmental laws and regulations. These laws and regulations can restrict or impact our business activities in many ways, including restricting the manner in which we dispose of wastes and other regulated substances, requiring remedial action to remove or mitigate contamination, and requiring capital expenditures to comply with 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 due to our handling of natural gas, NGLs and other hydrocarbons, air emissions related to our operations, historical industry operations, including

releases of substances into the environment, 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 not be able to recover some or any of these costs from insurance.

 

If the cost of renewing existing rights-of-way increases, it may have an adverse impact on our profitability. In addition, if we are unable to obtain new rights-of-way, then we may be unable to fully execute our growth strategy.

 

The construction of additions to our existing gathering and transportation assets may require us to obtain new rights-of-way prior to constructing new pipelines. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of renewing existing rights-of-way increases, then our results of operations could be adversely affected. In addition, increased rights-of-way costs could impair our ability to grow.

 

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:

 

 

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 the Texas Gulf Coast 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. For example, although we did not suffer significant damage due to Hurricane Ike in September 2008, the storm damaged gathering systems and processing and NGL fractionation facilities along the Gulf Coast, including facilities owned by third-party service providers on whom we depend in providing services to our customers. Some companies were required to curtail or suspend operations, which adversely affected various energy companies with assets in the region, including us.

 

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 covers only certain lost revenues arising from physical damage to our processing plants and certain pipeline facilities. 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 gathering, dehydration, treating, conditioning, processing, fractionation and transportation business, and as a result, our financial condition depends upon prices of, and continued demand for, natural gas and NGLs. Furthermore, substantially all of our assets are located in Texas, Oklahoma and Wyoming. Due to our limited diversification in asset type and location, an adverse development in one of these businesses or in 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 may limit 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:

 

 

Although we serve as operator of Webb Duval, managing member and operator of Southern Dome, managing member and field operator of Bighorn and managing member of Fort Union, certain substantive business decisions with respect to these entities require 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 some of these substantive business decisions 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 respective owners of these entities could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting their respective businesses and results of operations or prospects and, in turn, the amounts and timing of cash from operations distributed to their respective 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.

 

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 that we may issue at any time without the approval of our unitholders, including common units and other equity securities that rank senior to common units. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

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 the 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 the 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 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.

 

Despite the fact that we are a limited liability company under Delaware law, it is possible in certain circumstances for a 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.

 

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.

 

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, at the federal level, legislation has been proposed that would eliminate pass-through tax treatment for certain publicly traded limited liability companies. Although such legislation would not apply to us as currently proposed, it could be modified before enactment in a manner that does apply to us. 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 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 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 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 (known as 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 individual retirement accounts 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 United States 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 the common units.

 

Because we cannot match transferors and transferees of common units and for certain other reasons, 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 Department of the Treasury and the IRS 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. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

 

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 loaning their units.

 

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 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.

 

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 Texas, Oklahoma, Wyoming, Colorado and Louisiana. Although Texas and Wyoming do not currently impose a personal income tax, Oklahoma, Colorado and Louisiana do and 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 United States federal, state and local tax returns that may be required of such unitholder.

 

 

None.

 

 

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.

 

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.

 

 

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.

 

We are the managing member and a 37.04% interest owner in Fort Union, which owns a gas gathering system in Wyoming. Fort Union is the largest gatherer by volume of natural gas into WIC’s Medicine Bow Lateral. This lateral redelivers natural gas to downstream markets through the interconnecting interstate and intrastate pipelines that meet at the Cheyenne hub in Cheyenne, Wyoming.

 

On January 28, 2010, WIC submitted a filing to the FERC to change WIC’s capacity allocation procedures to allow WIC to cut nominated supplies that do not conform to a downstream pipeline’s minimum quality

specifications even though the supplies comply with the WIC tariff’s minimum quality specifications. Specifically, WIC proposes to add a new section to its tariff providing that, if a downstream pipeline refuses to accept delivery of natural gas for reasons related to either CO2 or Btu, then WIC may reduce natural gas receipts into WIC’s pipeline by first reducing the natural gas with the greatest variance from the applicable CO2 or Btu specifications(s).

 

Since all supplies sourced from WIC’s Medicine Bow Lateral currently have a lower Btu than natural gas sourced elsewhere on the WIC system, this would cause Medicine Bow Lateral supplies to be cut first and likely would cause Fort Union, in turn, to shut in certain producers on its system until Fort Union obtained adequate treating capacity. We are unable to predict whether the FERC will grant WIC’s request to cut nominated supplies that do not conform to a downstream pipeline’s minimum quality specifications. While we intend to contest WIC’s filing vigorously, if the FERC ultimately grants WIC’s request, then it could have an adverse impact on our cash flows from Fort Union in the near term until adequate treating capacity was in place.

 

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.

 

As a result of the Cimmarron acquisition and a smaller 2007 “bolt-on” acquisition, we, through wholly owned subsidiaries, assumed three natural gas purchase agreements with Targa North Texas LP (“Targa”) pursuant to which we have sold natural gas purchased from north Texas producers to Targa (the “Targa Agreements”). One of these agreements terminated on September 1, 2008, and the remaining agreements expire on October 1, 2010 and December 1, 2011. Because of a dispute regarding what portion, if any, of the natural gas we purchase from north Texas producers has been contractually dedicated for resale to Targa, our wholly owned subsidiary, River View Pipelines, L.L.C. (“River View”), filed suit against Targa in the 190th Judicial District Court in Harris County, Texas, on May 28, 2008, seeking a declaratory judgment that River View had no obligation to sell to Targa any natural gas River View purchases from wells located in Denton, Wise, Cooke or Montague Counties, Texas. In Targa’s response filed July 25, 2008, Targa sought a declaratory judgment that this natural gas was contractually dedicated to Targa and claimed unspecified monetary damages for alleged breaches of the Targa Agreements by River View and certain other wholly owned subsidiaries. In February 2010, we and Targa executed a settlement agreement resolving all claims made in the litigation, which was effective as of October 1, 2009. The terms of the settlement agreement did not have a material effect on our financial condition or results of operations for the fourth quarter of 2009 and are not expected to have a material effect on our results of operation in the future.

 

 

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 19, 2010, the closing market price for our common units was $23.56 per unit, and there were approximately 237 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.

 

 

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) to the extent we have sufficient available cash from operating surplus, as defined in our limited liability company 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 or operating surplus.

 

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” and “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Trends and Uncertainties.” 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.”

 

Class C Units

 

All of the 1,579,409 Class C units we issued in connection with our May 2007 acquisition of Cimmarron have converted into common units on a one to one basis (in increments of 394,852 on November 1, 2007, May 1, 2008 and November 1, 2008, and 394,853 on May 1, 2009). No vote of our common unitholders was required to convert the Class C units to common units.

Class D Units

 

Our 3,245,817 Class D units, which we issued to the Cantera sellers as part of the consideration for the Cantera acquisition, converted into our common units on a one-for-one basis on February 11, 2010. No vote of our common unitholders was required to convert the Class D units to common units.

 

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 November 9, 2004 (the day our units began trading on NASDAQ), 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.

Cumulative Total Unitholder Return

 

 

 

Notwithstanding anything to the contrary set forth in any of our previous or future filings under the Securities Act of 1933 or the Securities Exchange Act of 1934 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

 

None.

 

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 Operation.”

 

 

 

 

 

 

You should read the following discussion of our financial condition and results of operation in conjunction with the historical consolidated financial statements and notes thereto included elsewhere in this report. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical consolidated financial statements 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, we own and operate natural gas gathering and intrastate transmission pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. We operate in Oklahoma, Texas, 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: Oklahoma, Texas and Rocky Mountains.

 

 

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. Please Read Item 1A, “Risk Factors,” for a description of these factors and related risks.

 

Commodity Prices and Producer Activity

 

Our gross margins and total distributable cash flow are influenced by the prices of natural gas and NGLs, and by drilling activity. Generally, prices affect the cash flow and profitability of our Texas and Oklahoma segments directly. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly. Please read “— How We Evaluate Our Operations” and “— How We Manage Our Operations” for further discussion. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read Item 7A, “Quantitative and Qualitative Disclosures About Market Risk.”

 

The long-term growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives, capital and adequate returns for producers to maintain and increase natural gas exploration and production. Commodity price fluctuations and the availability of capital are among the factors that influence natural gas producers as they schedule drilling projects. Low natural gas prices act as a disincentive to producers, particularly when combined with high operating costs and high third-party transportation costs. Depending on the severity and duration of an unfavorable pricing environment, producers may suspend drilling and completion of

wells to the degree they have become uneconomic. We believe that future natural gas prices will be influenced by regional drilling activity, takeaway capacity, the severity of winter and summer weather, natural gas storage levels, liquefied natural gas imports, NGL transportation and fractionation capacity and the overall economy.

 

The financial and economic crises of late 2008 were accompanied by sharp declines in prices for oil, natural gas and NGLs. Prices for oil and NGLs have continued the recovery that began in the second quarter of 2009, and natural gas prices have also improved after remaining low through the third quarter. Forward pricing on NYMEX reflects market expectations that oil and natural gas prices in the coming months will be consistently higher compared to recent months. While recent economic indicators increasingly support the view that the recession has ended, the strength and sustainability of an economic recovery remain uncertain. A renewed slowdown in economic activity would likely result in continued lower natural gas prices and renewed declines in NGL prices, which in turn would delay a recovery in drilling activity.

 

Pricing Trends in Texas.  During the fourth quarter of 2009, NGL prices in Texas continued to improve, and natural gas prices recovered from lows experienced in the third quarter. Natural gas prices have remained relatively stable in the first quarter 2010 to date, and NGL prices continued to strengthen. First-of-the-month prices for natural gas on the Houston Ship Channel index were $5.83 per MMBtu for January and $5.48 per MMBtu for February 2010, and weighted-average daily prices for NGLs at Mt. Belvieu through February 18, 2010, based on our fourth quarter product mix, were $47.32 per barrel.

 

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

 

Texas Average Prices for Oil, Natural Gas and NGLs⁽¹⁾

 

 

 

 

Pricing Trends in Oklahoma.  Oklahoma natural gas and NGL prices improved throughout the fourth quarter of 2009. In the first quarter 2010 to date, natural gas prices remained relatively stable, and NGL prices continued to

strengthen. First-of-the-month prices for natural gas on CenterPoint East were $5.67 per MMBtu for January and $5.33 per MMBtu for February 2010, and weighted-average daily prices for NGLs at Conway through February 18, 2010, based on our fourth quarter product mix, were $44.33 per barrel.

 

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

 

Oklahoma Average Prices for Oil, Natural Gas and NGLs⁽¹⁾

 

 

 

 

Basis Trends.  During the third quarter, Mt. Belvieu NGL prices improved at a faster rate than Conway NGL prices, resulting in a widening basis differential that reached $9.95 per barrel in August 2009. Prices for the fourth quarter and the beginning of 2010 indicate substantial moderation in this trend. The average basis differential between Mt. Belvieu and Conway of $7.47 per barrel for the third quarter of 2009 narrowed to $2.09 per barrel for the fourth quarter of 2009. At February 18, 2010, this basis differential was $2.99 per barrel. Houston Ship Channel and CenterPoint East natural gas index prices also reflected greater variability that persisted for much of 2009, but fourth quarter of 2009 prices reflect a closer correlation between the two indices. The average basis differential between Houston Ship Channel and CenterPoint East was $0.34 for the third quarter and $0.52 for all of 2009, but by the fourth quarter of 2009 had narrowed to $0.15.

 

Pricing Trends in the Rocky Mountains.  Rocky Mountains natural gas prices improved throughout the fourth quarter of 2009 and remained stronger in the first quarter 2010 to date. First-of-the-month prices for natural gas on the Colorado Interstate Gas (“CIG”) index were $5.54 per MMBtu for January and $5.32 per MMBtu for February 2010.

 

The following graph and table summarize quarterly average prices for natural gas on CIG, the primary index we use for the Rocky Mountains.

Rocky Mountains Average Prices for Natural Gas

 

 

 

 

 

Trends in Drilling and Production Activity.  Drilling activity has remained low due to the weaker pricing environment that prevailed for much of 2009. We experienced a decreases in 2009 volumes compared to 2008, largely due to lower volumes in Texas and the Rocky Mountains (including Bighorn and Fort Union), and offset in part by higher volumes in Oklahoma. Within the Rocky Mountains, lower volumes on Bighorn and for our producer services were offset by higher volumes on Fort Union. These volume decreases are attributable partly to lower drilling activity; however, a decrease in low-margin gas from a third-party pipeline was also a significant factor in Texas. Compared to the third quarter of 2009, fourth-quarter volumes reflect decreases in Texas and Oklahoma, while Rocky Mountains volumes (including Bighorn and Fort Union) were relatively flat. Although commodity prices and financial market conditions have continued to recover, improvements in drilling activity have been sporadic, and it remains uncertain when producers will undertake sustained increases in drilling activity throughout the areas in which we operate.

 

We anticipate that producers generally will increase new drilling activity once natural gas prices or NGL prices reach a level sufficient to make drilling and production economic. The level at which drilling and production become economic depends on various factors, including the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir, among other things. These costs have declined significantly since late 2008, but other considerations, such as demand for and competing supplies of natural gas, and their anticipated effects on natural gas prices, will also influence producers’ decisions regarding drilling. For producers of rich gas who share in the benefits of improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset as prices for condensate and NGLs increase. In addition, improving oil prices could lead to increased production of casinghead natural gas associated with oil production.

If the pricing environment of the fourth quarter of 2009 continues, we anticipate that we will see sustained or increasing drilling activity in areas that produce rich gas, for example the Eagle Ford Shale trend in south Texas, the Barnett Shale Combo play in north Texas and the Hunton play in Oklahoma, and a continued low level of drilling activity in areas that produce lean gas, for example the Woodford Shale in Oklahoma and the Powder River Basin in Wyoming. We expect that many producers of lean gas will wait to see sustained increases in natural gas prices before resuming significant drilling activity. Forward pricing on NYMEX suggests that natural gas prices will improve in the near future; however, forward curves only reflect market expectations, and it is uncertain to what extent they will influence producers’ drilling decisions. Any prolonged decrease in oil, NGL and natural gas prices would further depress the current levels of exploration, development and production activity, which in turn would negatively affect our results of operation. In addition, once drilling activity increases, a recovery in volumes will be subject to delays ranging from three months to as long as 18 months, depending on the characteristics of the reservoir, for processes involved in completing and attaching new wells.

 

Please read “— Critical Accounting Policies — Impairment of Long-Lived Assets” below, and Item 1A, “Risk Factors— Risks Related to our Business.”

 

Other Industry Trends.  Due to higher NGL prices and the completion of projects increasing NGL output, NGL fractionation facilities are experiencing capacity constraints, which we believe could lead to erosion in the processing margins received from NGLs. If NGL fractionation capacity remains constrained, the effect on NGL revenue could offset the benefits of improving NGL market prices to some extent. We plan to restart our fractionator at Houston Central, which will allow us to sell purity ethane and purity propane through separate pipelines and purity iso-butane and purity normal butane through truck racks, helping to offset the effect of fractionation capacity constraints on our NGL revenue in Texas. We anticipate completing this project late in the first quarter of 2010.

 

Credit and Capital Market Disruptions.  The effects of late-2008 disruptions in financial markets worldwide continue to influence the availability of debt and equity capital, although to a lesser degree. Generally, we believe that the markets have recovered significantly since the height of the financial crisis, but the cost of capital remains higher than before the financial crisis. To the extent we access financial markets in the near term, we believe that we would be able to raise debt and equity on acceptable terms, assuming that market conditions remained substantially similar to current conditions.

 

Renewed instability in the financial markets, as a result of developments in the recent recession or otherwise, would have a negative impact on the cost and accessibility of capital for us, and for our customers and suppliers.

 

Factors Affecting Operating Results and Financial Condition

 

Our results for the year ended December 31, 2009 reflect the lower prices and lower volumes we encountered in 2009 compared to the high commodity prices and increasing volumes that prevailed during much of 2008. A comparison of the third and fourth quarters of 2009, however, reveals the continuing benefits of strengthening NGL prices. Higher NGL prices overall combined with relatively stable natural gas prices in Texas during the fourth quarter of 2009 have led to continued improvement in our processing margins compared to the third quarter. As a result of improvement in NGL prices, our combined operating segment gross margins increased 32% compared to the third quarter of 2009.

 

Consistent with our business strategy, we have used derivative instruments to mitigate the effects of commodity price fluctuations on our cash flow and profitability so that we can continue to meet our debt service and capital expenditure requirements, and our distribution objectives. For the fourth quarter and year ended December 31, 2009, we received $6.4 million and $68.7 million, respectively, in cash settlements from our commodity hedge portfolio, which helped to offset the decline in operating revenues attributable to lower commodity prices. The basis spread between Mt. Belvieu and Conway limited the benefit we received from our NGL hedging portfolio because we hedge Oklahoma NGL volume with hedge instruments based on Mt. Belvieu prices. For the fourth quarter and year ended December 31, 2008, we received $27.5 million and $8.0 million, respectively, in cash settlements from our commodity hedge portfolio. Our results also reflect lower general and administrative and operating expenses due to our continuing cost control efforts.

How We Evaluate Our Operations

 

We believe that investors benefit from having access to the various financial and operating measures that our management uses in evaluating our performance. These measures include the following: (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-GAAP financial measures. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below.

 

Throughput Volumes.  Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes delivered to our 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 significantly influenced by the volume of natural gas delivered to the plant, the NGL content of the natural gas, the quality of the natural gas and the plant’s recovery capability. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs and losses associated with our pipeline operations, these costs are frequently passed on to our producers under contractual agreements.

 

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 Oklahoma and Texas segments evaluate what we refer to as service throughput, which consists of two components:

 

 

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.

 

In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered using our firm capacity gathering agreements with Fort Union and volumes transported using our firm transportation agreements with WIC, or using additional capacity that we obtain on WIC. We also regularly assess the pipeline throughput of Bighorn and Fort Union.

 

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 purchase and costs for transportation 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 Oklahoma and Texas segments, our management analyzes segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn and Fort Union.

 

Our Oklahoma margins are, on the whole, positively correlated with NGL prices and natural gas prices. In Texas, increases in natural gas prices or decreases in NGL prices generally have a negative impact on margins, and, conversely, a reduction in natural gas prices or an increase in NGL prices generally has a positive impact. However, when we operate our Houston Central plant in conditioning mode, increases in natural gas prices have a positive impact on our margins. The profitability of our Rocky Mountains operations is not directly affected by commodity prices. Substantially all of our Rocky Mountains contract portfolio, as well as Bighorn’s and Fort Union’s contract portfolios, consists of fixed-fee arrangements providing for an agreed gathering fee per unit of natural gas throughput. Our revenues from these arrangements are directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent that low commodity prices

discourage drilling activity and result in declining volumes, however, our revenues under these arrangements will also decline.

 

To measure the overall financial impact of our contract portfolio, we use total segment gross margin, which 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 of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas, 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.

 

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. Through December 31, 2009, a portion of our operations and maintenance expenses was incurred through Copano Operations, an affiliate of our company, which was controlled by our late founder, Chairman and Chief Executive Officer, John R. Eckel, Jr. For further information, please read Note 9, “Related Party Transactions,” to our consolidated financial statements included in Item 8 of this report. Under the terms of our arrangement with Copano Operations, we reimbursed it, at cost, for the operations and maintenance expenses it incurred on our behalf, which consisted primarily of payroll costs. 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. Through December 31, 2009, a portion of our general and administrative expenses were incurred through Copano Operations, an affiliate of our company. For further information, please read Note 9, “Related Party Transactions,” to our consolidated financial statements included in Item 8 of this report. Under the terms of our arrangement with Copano Operations, we agreed to reimburse it, at cost, for the general and administrative expenses it incurred on our behalf. To help ensure the appropriateness of our general and administrative expenses, we monitor such expenses through comparison with general and administrative expenses incurred by similar midstream companies and with 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, amortization and impairment expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and Southern Dome), our management also calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, our management determines adjusted EBITDA by adding to EBITDA (i) the amortization expense attributable to the difference between our carried investment in

each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate’s depreciation and amortization expense which is proportional to our ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs which is proportional to our ownership interest in that unconsolidated affiliate.

 

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:

 

 

EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to our lenders and used to compute financial covenants under our revolving credit facility. Neither EBITDA nor adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP.

 

Total Distributable Cash Flow.  We define total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense relating to the option component of our risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v) the subtraction of equity in earnings from unconsolidated affiliates and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and our line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed 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.

 

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.

 

Although we have previously reported both distributable cash flow and total distributable cash flow, we determined that total distributable cash flow is a better measure of the rate at which cash available for distribution is generated by our operations than distributable cash flow, which does not add back the amortization expense relating to the option component of our risk management portfolio. Total distributable cash flow should not be considered an

alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

 

 

 

 

How We Manage Our Operations

 

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

 

Economic Models and Standardized Processing Margin.  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 process natural gas, reject ethane or condition natural gas at our Houston Central and Saint Jo plants.

 

To isolate and consistently track changes in commodity price relationships and their impact on our Texas segment’s results from its processing operations, we calculate a hypothetical “standardized” processing margin at our Houston Central plant. Our processing margin refers to the difference between the market value of:

 

 

Our “standardized” processing margin is based on a fixed set of assumptions, with respect to NGL composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices, such as volumes, changes in NGL composition, recovery rates and variable contract terms. However, we believe this calculation is representative of the current operating commodity price environment of our Texas processing operations, and we use this calculation to track commodity price relationships. Our standardized processing margins averaged $0.3903, $0.4336 and $0.4578 per gallon during the years ended December 31, 2009, 2008 and 2007, respectively. The average standardized processing margin for the period from January 1, 1989 through December 31, 2009 is $0.1478 per gallon.

 

Flow and Transaction Monitoring Systems.  We use automated systems that track commercial activity on each of our Texas segment pipelines and monitor the flow of natural gas on all of our pipelines. In our Texas segment, we designed and implemented software that tracks 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 one 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.

 

Our Contracts

 

We seek to execute contracts with producers and shippers that allow us to maintain positive gross margin even in adverse natural gas and NGL pricing environments. We enter into a variety of contractual arrangements, including fee-based, percentage-of-proceeds, percentage-of-index and keep-whole with fee arrangements. Actual contract terms vary based upon a variety of factors, including gas quality, pressures of natural gas production relative to downstream transporter pressure requirements, the competitive environment at the time the contract is executed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, gas quality, downstream transporter gas quality specifications, our expansion in regions where some types of contracts are more common and other market factors.

 

Our most common contractual arrangements for gathering, transporting, processing and conditioning natural gas are summarized below. In our Oklahoma and Texas segments, we often provide services under contracts that reflect a combination of these contract types, while substantially all of our Rocky Mountains segment’s contracts reflect fixed-fee arrangements. Fort Union’s and Bighorn’s contractual arrangements are entirely fixed-fee.

 

In addition to providing for compensation for our gathering, transportation, processing or conditioning services, in many cases, our contracts for natural gas supplies also allow us to charge producers fees for treating, compression, dehydration or other services. Additionally, we may share a fixed or variable portion of our processing margins with the producer or third-party transporter in the form of “processing upgrade” payments during periods where such margins are in excess of an agreed-upon amount.

 

Fee-Based Arrangements.  Under fee-based arrangements, producers or shippers pay us an agreed rate per unit of throughput to gather or transport their natural gas. The agreed rate may be a fixed fee or based upon a percentage of index price. The revenue we earn from fixed-fee arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. However, to the extent a sustained decline in commodity prices results in a decline in volumes, our revenues from these arrangements would be reduced. When the fee is based upon a percentage of index price, the fee decreases in periods of low natural gas prices and increases during periods of high natural gas prices.

 

Percentage-of-Proceeds Arrangements.  Under percentage-of-proceeds arrangements, we generally gather and process natural gas on behalf of producers and sell the residue gas and NGL volumes at index-related prices. We remit to producers an agreed upon percentage of the proceeds we receive from the sale of residue gas and NGLs. Under these types of arrangements, our revenues and gross margins increase as natural gas and NGL prices increase and our revenues and gross margins decrease as natural gas and NGL prices decrease.

 

Percentage-of-Index Arrangements.  Under percentage-of-index arrangements, we purchase natural gas at either (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) a percentage discount to a specified index price less an additional fixed amount. We then gather, deliver and resell the natural gas at an index-based price. The gross margins we realize under the arrangements described in clauses (i) and (iii) above decrease in periods of low natural gas prices and increase during months of high natural gas prices because these gross margins are based on a percentage of the index price.

 

Keep-Whole with Fee Arrangements.  Under keep-whole with fee arrangements, we receive natural gas from producers and third-party transporters, either process or condition the natural gas at our election, sell the resulting NGLs to third parties at market prices for our account and redeliver the residue gas to the producer or third-party transporter. We determine whether to process or condition the natural gas based upon the relationship between natural gas and NGL prices. Because the extraction of NGLs from the natural gas during processing or conditioning reduces the Btu content of the natural gas, we must purchase natural gas at market prices for return to producers or third-party transporters to keep them whole. Accordingly, under these arrangements, our revenues and gross margins increase as the price of NGLs increase relative to the price of natural gas, and our revenues and gross

margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, we are generally able to reduce our commodity price exposure by conditioning rather than processing the natural gas. Under our keep-whole with fee arrangements, we also charge producers and third-party transporters a conditioning fee, at all times or in certain circumstances depending upon the terms of the particular contract. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. It is generally not our policy to enter into new keep-whole contracts without fee arrangements or pricing provisions that provide positive gross margins during conditioning periods. For a discussion of our processing and conditioning capabilities, please read Item 1, “Business — Our Operations — Texas” of this report.

 

Our Contracts with Kinder Morgan.  We use Kinder Morgan as a transporter because our Houston Central plant straddles its 30-inch-diameter Laredo-to-Katy pipeline, which allows us to move natural gas from our pipeline systems in south Texas and near the Texas Gulf Coast to our Houston Central plant and downstream markets. Kinder Morgan’s pipeline also delivers to the Houston Central plant natural gas for its own account, which we refer to as “KMTP Gas.” Under agreements with Kinder Morgan and with other producers or transporters whose gas Kinder Morgan has delivered to us, we process or condition the gas and sell the NGLs to third parties at market prices. Under our processing agreement with Kinder Morgan, after processing or conditioning KMTP Gas, we make up for the reduction in Btu content resulting from extracting NGLs from the natural gas stream using natural gas that we purchase from producers at market prices. Our processing agreement with Kinder Morgan also provides that we make a processing payment to Kinder Morgan during periods of favorable processing margins, which allows Kinder Morgan to share in the profitability of processing gas. During periods of unfavorable processing margins, Kinder Morgan instead pays us the lesser of (i) the difference between the processing margin and a specified threshold or (ii) a fixed fee per Mcf of KMTP Gas.

 

We also have a gas transportation agreement and a related gas sales agreement with Kinder Morgan. Each of our agreements with Kinder Morgan extends through January 31, 2011, with automatic annual renewals thereafter unless canceled by either party upon 180 days’ prior written notice, in the case of the processing and gas transportation agreements, or 30 days’ prior written notice, in the case of the sales agreement.

 

For the year ended December 31, 2009, approximately 80% of the natural gas volumes processed or conditioned at our Houston Central plant were delivered to the plant through the Kinder Morgan Laredo-to-Katy pipeline, while the remaining 20% were delivered directly to the plant from our Houston Central gathering systems. Of the volumes delivered from the Kinder Morgan Laredo-to-Katy pipeline, approximately 38% were from our gathering systems or under our contracts, while 62% were “KMTP Gas.” Of the total NGLs extracted at the plant during this period, 29% originated from KMTP Gas, and 71% from our south Texas gathering systems, including our Houston Central gathering systems.

 

Our Long-Term Growth Strategy

 

As part of our long-term growth strategy, we continue to review complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. We pursue acquisitions and capital projects that we believe will allow us to capitalize on our existing infrastructure, personnel and relationships with producers and customers to provide midstream services. We also evaluate acquisitions in new geographic areas to the extent they offer cash flow and operational growth opportunities that are attractive to us, as well as installation or construction of significant new facilities in such areas. To consummate larger acquisitions or complete significant organic expansion or greenfield projects, we will require access to additional capital on competitive terms. Generally, we believe that, over the long term, our cost of equity capital relative to master limited partnerships (“MLPs”) of similar size will be favorable because, unlike many of our competitors that are MLPs, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as per-unit cash distributions increase. If possible under then-existing market conditions, we intend to finance future large acquisitions and significant organic expansion or greenfield projects primarily through the issuance of debt and equity. For a more detailed discussion of our capital resources, including the effects of capital market conditions on our ability to implement our growth strategy, please read “— Liquidity and Capital Resources.”

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 business strategy, 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 will generate in comparison to our cost of capital under various commodity price scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.

 

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:

 

 

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. The 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.

Our Results of Operation