Form 10-K
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

 

x

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

For the fiscal year ended December 31, 2009

OR

 

¨

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

For the transition period from              to             

Commission file number: 000-51757

 

 

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

 

Delaware   16-1731691
(State or other jurisdiction of
incorporation or organization)
 

(I.R.S. Employer

Identification No.)

2001 Bryan Street

Suite 3700, Dallas, Texas

  75201
(Address of principal executive offices)   (Zip Code)

(214) 750-1771

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report): None

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

 

                                  Title of Each Class                            

 

Name of Each Exchange on Which Registered

Common Units of Limited Partner Interests   The Nasdaq Global Select Market

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

 

 

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

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  ¨    No  x

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405) 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.     ¨

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 small reporting company” in Rule 12b-2 of the Exchange Act.    x  Large accelerated filer    ¨  Accelerated filer ¨  Non-accelerated filer (Do not check if a smaller reporting company)    ¨  Smaller reporting company

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

As of June 30, 2009, the aggregate market value of the registrant’s common units held by non-affiliates of the registrant was $821,947,250 based on the closing sale price as reported on the NASDAQ Global Select Market.

There were 93,174,103 common units outstanding as of February 23, 2010.

DOCUMENTS INCORPORATED BY REFERENCE

None

 

 

 


Table of Contents

REGENCY ENERGY PARTNERS LP

ANNUAL REPORT ON FORM 10-K

FOR THE YEAR ENDED DECEMBER 31, 2009

TABLE OF CONTENTS

 

          PAGE
  

Introductory Statement

  
  

Cautionary Statement about Forward-Looking Statements

  

Item 1

  

Business

   1

Item 1A

  

Risk Factors

   18

Item 1B

  

Unresolved Staff Comments

   37

Item 2

  

Properties

   37

Item 3

  

Legal Proceedings

   38

Item 4

  

Reserved

   38

Item 5

  

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

   39

Item 6

  

Selected Financial Data

   41

Item 7

  

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

   45

Item 7A

  

Quantitative and Qualitative Disclosure about Market Risk

   70

Item 8

  

Financial Statements and Supplementary Data

   71

Item 9

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   71

Item 9A

  

Controls and Procedures

   72

Item 9B

  

Other Information

   73

Item 10

  

Directors, Executive Officers and Corporate Governance

   74

Item 11

  

Executive Compensation

   81

Item 12

  

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

   105

Item 13

  

Certain Relationships and Related Transactions, and Director Independence

   107

Item 14

  

Principal Accounting Fees and Services

   107

Item 15

  

Exhibit and Financial Statement Schedules

   109

 


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Introductory Statement

References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in an historical context, refer to Regency Energy Partners LP, and to Regency Gas Services LLC, all the outstanding member interests of which were contributed to the Partnership on February 3, 2006, and its subsidiaries. When used in the present tense or prospectively, these terms refer to the Partnership and its subsidiaries. We use the following definitions in this annual report on Form 10-K:

 

Name

  

Definition or Description

Alinda

  

Alinda Capital Partners LLC, a Delaware limited liability company that is an independent private investment firm specializing in infrastructure investments

Alinda Investor I

  

Alinda Gas Pipelines I, L.P., a Delaware limited partnership

Alinda Investor II

  

Alinda Gas Pipelines II, L.P., a Delaware limited partnership

Alinda Investors

  

Alinda Investor I and Alinda Investor II, collectively

ASC

  

ASC Hugoton LLC, an affiliate of GECC

Bbls/d

  

Barrels per day

Bcf

  

One billion cubic feet

Bcf/d

  

One billion cubic feet per day

BTU

  

A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit

CDM

  

CDM Resource Management LLC

CERCLA

  

Comprehensive Environmental Response, Compensation and Liability Act

CFTC

  

Commodity Futures Trading Commission

DHS

  

Department of Homeland Security

DOT

  

U.S. Department of Transportation

EFS Haynesville

  

EFS Haynesville, LLC, a 100 percent owned subsidiary of GECC

EIA

  

Energy Information Administration

Enbridge

  

Enbridge Pipelines (NE Texas), LP, Enbridge Pipeline (Texas Interstate), LP and Enbridge Pipelines (Texas Gathering), LP

EnergyOne

  

FrontStreet EnergyOne LLC

El Paso

  

El Paso Field Services, LP

EPA

  

Environmental Protection Agency

FASB

  

Financial Accounting Standards Board

FASB ASC

  

FASB Accounting Standards Codification

FASB ASU

  

FASB Accounting Standards Update

FERC

  

Federal Energy Regulatory Commission

Finance Corp.

  

Regency Energy Finance Corp., a wholly-owned subsidiary of the Partnership

FrontStreet

  

FrontStreet Hugoton LLC, a wholly-owned subsidiary of the Partnership

GAAP

  

Accounting principles generally accepted in the United States

GE

  

General Electric Company

GE EFS

  

General Electric Energy Financial Services, a unit of GECC, combined with Regency GP Acquirer LP and Regency LP Acquirer LP

GECC

  

General Electric Capital Corporation, an indirect wholly owned subsidiary of GE

General Partner

  

Regency GP LP, the general partner of the Partnership, or Regency GP LLC, the general partner of Regency GP LP, which effectively manages the business and affairs of the Partnership through Regency Employees Management LLC

GPM

  

Gallons per minute

GSTC

  

Gulf States Transmission Corporation, a wholly-owned subsidiary of the Partnership

HLPSA

  

Hazardous Liquid Pipeline Safety Act

HM Capital Investors

  

Regency Acquisition LP, HMTF Regency L.P., HM Capital Partners and funds managed by HM Capital Partners, including Fund V, and certain Co-investors, including some of the directors and officers of the General Partner.

HM Capital Partners

  

HM Capital Partners LLC


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Name

  

Definition or Description

HPC

  

RIGS Haynesville Partnership Co., a general partnership that owns 100 percent of RIG

ICA

  

Interstate Commerce Act

IDRs

  

Incentive Distribution Rights

IPO

  

Initial Public Offering of Securities

IRS

  

Internal Revenue Service

Lehman

  

Lehman Brothers Holdings, Inc.

LIBOR

  

London Interbank Offered Rate

LTIP

  

Long-Term Incentive Plan

MLP

  

Master Limited Partnership

MMbtu

  

One million BTUs

MMbtu/d

  

One million BTUs per day

MMcf

  

One million cubic feet

MMcf/d

  

One million cubic feet per day

MQD

  

Minimum Quarterly Distribution

NAAQS

  

National Ambient Air Quality Standards

Nasdaq

  

Nasdaq Stock Market, LLC

Nexus

  

Nexus Gas Holdings, LLC

NGA

  

Natural Gas Act of 1938

NGLs

  

Natural gas liquids, including ethane, propane, butane and natural gasoline

NGPA

  

Natural Gas Policy Act of 1978

NGPSA

  

Natural Gas Pipeline Safety Act of 1968, as amended

NOE

  

Notice of Enforcement

NPDES

  

National Pollutant Discharge Elimination System

NYMEX

  

New York Mercantile Exchange

OSHA

  

Occupational Safety and Health Act

Partnership

  

Regency Energy Partners LP

Pueblo

  

Pueblo Midstream Gas Corporation, a wholly-owned subsidiary of the Partnership

RCRA

  

Resource Conservation and Recovery Act

Regency HIG

  

Regency Haynesville Intrastate Gas LLC, a wholly owned subsidiary of the Partnership

RFS

  

Regency Field Services LLC, a wholly-owned subsidiary of the Partnership

RGS

  

Regency Gas Services LP, a wholly-owned subsidiary of the Partnership

RIG

  

Regency Intrastate Gas LP, a wholly-owned subsidiary of HPC, which was converted from Regency Intrastate Gas LLC upon HPC formation

RIGS

  

Regency Intrastate Gas System

SCADA

  

System Control and Data Acquisition

SEC

  

Securities and Exchange Commission

Sonat

  

Southern Natural Gas Company

TCEQ

  

Texas Commission on Environmental Quality

Tcf

  

One trillion cubic feet

Tcf/d

  

One trillion cubic feet per day

TexStar

  

TexStar Field Services, L.P. and its general partner, TexStar GP, LLC

TRRC

  

Texas Railroad Commission

WTI

  

West Texas Intermediate Crude

Cautionary Statement about Forward-Looking Statements

Certain matters discussed in this report include “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify


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forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions, including without limitation the following:

 

 

 

volatility in the price of oil, natural gas, and natural gas liquids;

 

 

 

declines in the credit markets and the availability of credit for us as well as for producers connected to our system and our customers;

 

 

 

the level of creditworthiness of, and performance by, our counterparties and customers;

 

 

 

our access to capital to fund organic growth projects and acquisitions, and our ability to obtain debt or equity financing on satisfactory terms;

 

 

 

our use of derivative financial instruments to hedge commodity and interest rate risks;

 

 

 

the amount of collateral required to be posted from time-to-time in our transactions;

 

 

 

changes in commodity prices, interest rates, and demand for our services;

 

 

 

changes in laws and regulations impacting the midstream sector of the natural gas industry;

 

 

 

weather and other natural phenomena;

 

 

 

industry changes including the impact of consolidations and changes in competition;

 

 

 

regulation of transportation rates on our natural gas pipelines;

 

 

 

our ability to obtain required approvals for construction or modernization of our facilities and the timing of production from such facilities; and

 

 

 

the effect of accounting pronouncements issued periodically by accounting standard setting boards.

If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may differ materially from those anticipated, estimated, projected or expected.

Other factors that could cause our actual results to differ from our projected results are discussed in Item 1A of this annual report.

Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise.


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Item 1. Business

OVERVIEW

We are a growth-oriented publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, processing, contract compression and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma. Our midstream assets are located in historically well-established areas of natural gas production that have been characterized by long-lived, predictable reserves.

We divide our operations into four business segments:

 

 

 

Gathering and Processing: We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems;

 

 

 

Transportation: We own a 43 percent interest in HPC, which, through RIGS, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system;

 

 

 

Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations; and

 

 

 

Corporate and Others: We own and operate an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. This pipeline has a FERC certificated capacity of 150 MMcf/d.

The following map depicts the geographic areas of our operations.

LOGO

 

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RECENT DEVELOPMENTS

Subsequent to December 31, 2009, our Contract Compression segment placed in service approximately 3,000 revenue generating horsepower in Pennsylvania to compress natural gas in the Marcellus Shale and we are currently working with customers as to the timing of placing in service an additional revenue generating horsepower of approximately 4,000 in 2010.

INDUSTRY OVERVIEW

General. The midstream natural gas industry is the link between exploration and production of raw natural gas and the delivery of its components to end-user markets. It consists of natural gas gathering, compression, dehydration, processing and treating, fractionation, and transportation. Raw natural gas produced from the wellhead is gathered and often delivered to a plant located near the production, where it is treated, dehydrated, and/or processed. Natural gas processing involves the separation of raw natural gas into pipeline quality natural gas, principally methane, and mixed NGLs. Natural gas treating entails the removal of impurities, such as water, sulfur compounds, carbon dioxide and nitrogen. Pipeline-quality natural gas is delivered by interstate and intrastate pipelines to markets. Mixed NGLs are typically transported via NGL pipelines or by truck to fractionators, which separates the NGLs into their components, such as ethane, propane, normal butane, isobutane and natural gasoline. The NGL components are then sold to end users.

The following diagram depicts our role in the process of gathering, processing, compression and transporting natural gas.

LOGO

Gathering. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collects natural gas from points near producing wells and transports it to processing or treating plants or larger diameter pipelines for further transportation.

Compression. Ideally-designed gathering systems are operated at pressures that maximize the total through-put volumes from all connected wells. Natural gas compression is a mechanical process in which a volume of gas at a lower pressure is boosted, or compressed, to a desired higher pressure, allowing the gas to flow into a higher pressure downstream pipeline to be transported to market. Since natural gas wells produce gas at progressively lower field pressures as they age, this raw natural gas must be compressed to deliver the remaining production at higher pressures in the existing connected gathering system. This field compression is typically used to lower the suction (entry) pressure, while maintaining or increasing the discharge (exit) pressure to the gathering system which allows the well production to flow at a lower receipt pressure while providing sufficient pressure to deliver gas into a higher pressure downstream pipeline.

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

Processing. Natural gas processing involves the separation of natural gas into pipeline quality natural gas and a mixed NGL stream. The principal component of natural gas is methane, but most natural gas also contains

 

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varying amounts of heavier hydrocarbon components, or NGLs. Natural gas is described as lean or rich depending on its content of NGLs. Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use because it contains NGLs and impurities. Removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics.

Fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, normal butane, isobutane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Propane is used both as a petrochemical feedstock in the production of propylene and as a heating fuel, an engine fuel and an industrial fuel. Normal butane is used as a petrochemical feedstock in the production of butadiene (a key ingredient in synthetic rubber) and as a blend stock for motor gasoline. Isobutane is typically fractionated from mixed butane (a stream of normal butane and isobutane in solution), principally for use in enhancing the octane content of motor gasoline. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We do not own or operate any NGL fractionation facilities.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing or treating plants and other pipelines and delivering it to wholesalers, utilities and other pipelines.

Overview of U.S. market. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas wells. Natural gas remains a critical component of energy consumption in the United States. According to the EIA, total annual production of natural gas is expected to increase 14 percent from 20.6 Tcf in 2008 to 23.3 Tcf in 2035. Natural gas production from shale formations is expected to grow to 6.0 Tcf by 2035, more than offsetting the decline in conventional production. EIA projects that natural gas and renewable power plants will account for the majority of electricity generation capacity addition by 2035.

Short-Term Energy Outlook. At December 31, 2009, the working natural gas drilling rig count totaled 759 compared to 665 in mid July of 2009, a 14 percent increase. EIA expects a 3 percent decline in natural gas production in 2010 due to the natural decline in existing well production and the lagged effect of reduced drilling. EIA also expects production to increase by 1.3 percent in 2011. Demand for natural gas in 2010 is expected to remain unchanged. EIA expects that higher prices for natural gas in 2010 will drive lower consumption in the electric power generation sector by 2.8 percent; this decline is expected to be offset by growth in the residential, commercial and industrial sectors. EIA projects that natural gas consumption in 2011 will increase by 0.4 percent, led by a 2.5 percent increase in consumption in the industrial sector. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

EIA forecasts demand for crude oil and NGLs to increase in years 2010 and 2011. Total petroleum consumption is forecasted to increase by 1.1 percent in 2010, with all of the major sectors contributing to this increase.

GATHERING AND PROCESSING OPERATIONS

General. We operate gathering and processing assets in five geographic regions of the United States: north Louisiana, the mid-continent region of the United States, and east, south and west Texas. We contract with producers to gather raw natural gas from individual wells or central delivery points, which may have multiple wells behind them, located near our processing plants, treating facilities and/or gathering systems. Following the execution of a contract, we connect wells and central delivery points to our gathering lines through which the raw natural gas flows to a processing plant, treating facility or directly to interstate or intrastate gas transportation pipelines. At our processing plants and treating facilities, we remove impurities from the raw natural gas stream

 

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and extract the NGLs. We also perform a producer service function, whereby we purchase natural gas from producers at gathering systems and plants and sell this gas at downstream outlets.

All raw natural gas flowing through our gathering and processing facilities is supplied under gathering and processing contracts having terms ranging from month-to-month to the life of the oil and gas lease. For a description of our contracts, please read “—Our Contracts” and “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Operations.”

The pipeline-quality natural gas remaining after separation of NGLs through processing is either returned to the producer or sold, for our own account or for the account of the producer, at the tailgates of our processing plants for delivery to interstate or intrastate gas transportation pipelines.

The following table sets forth information regarding our gathering systems and processing plants as of December 31, 2009.

 

Region

   Pipeline
Length
(Miles)
   Plants    Compression
(Horsepower)

North Louisiana

   407    4    58,937

East Texas

   371    1    20,009

South Texas

   541    2    24,779

West Texas

   806    1    58,008

Mid-Continent

   3,470    1    43,519
              

Total

   5,595    9    205,252
              

North Louisiana Region. Our north Louisiana region assets include:

 

 

 

Two cryogenic natural gas processing facilities;

 

 

 

A large integrated natural gas gathering and processing system located primarily in four parishes (Claiborne, Union, Lincoln, and Ouachita) of north Louisiana;

 

 

 

The Logansport Gathering System, which provides natural gas gathering, dehydration and compression services for producers in Shelby County, Texas and Desoto Parish, Louisiana. In 2009, we announced Logansport Expansion Phase I, a $47,000,000 extension of the Logansport Gathering System in north Louisiana, and Logansport Expansion Phase II, a $40,000,000 expansion to gather gas from acreage dedicated to Logansport Expansion Phase I. Logansport Expansion Phase I is expected to add approximately 485 MMcf/d of gathering capacity and add approximately 300 MMcf/d of new delivery interconnect capacity to CenterPoint Gas Transmission’s Line CP. Logansport Expansion Phase II includes the construction of an amine treating plant with capacity of 300 MMcf/d, approximately 15 miles of gathering lines and expanded interconnect capacity at Tennessee Gas Pipeline and Crosstex LIG, LLC by 100 MMcf/d and 35 MMcf/d, respectively. The Logansport Expansion Phase I and II projects are expected to be completed during 2010; and

 

 

 

A refrigeration plant located in Bossier Parish and a conditioning plant in Webster Parish.

Through the gathering and processing systems described above and their interconnections with HPC’s pipeline system in north Louisiana described in “—Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing and transportation.

East Texas Region. Our east Texas assets gather, compress, process and dehydrate natural gas through a large integrated natural gas gathering and processing system located in Rains, Wood, Van Zandt, Henderson, Franklin, and Hopkins counties that delivers natural gas to our east Texas processing plant. Our east Texas processing plant is a cryogenic natural gas processing plant that was constructed in Henderson County, Texas in

 

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1981. It includes an amine treating unit, a cryogenic NGL recovery unit, a nitrogen rejection unit, and a liquid sulfur recovery unit. This plant removes hydrogen sulfide, carbon dioxide and nitrogen from the natural gas stream, recovers NGLs and condensate, delivers pipeline quality natural gas at the plant outlet and produces sulfur.

The natural gas supply for our east Texas gathering systems comes primarily from natural gas wells that are located in a mature basin that generally have long lives, predictable gas flow rates, and high levels of hydrogen sulfide.

South Texas Region. Our south Texas assets gather, compress, treat, and dehydrate natural gas in LaSalle, Webb, Karnes, Atascosa, McMullen, Frio, and Dimmitt counties. Some of the natural gas produced in this region can have significant quantities of hydrogen sulfide and carbon dioxide that require treating to remove these impurities. The pipeline systems that gather this gas are connected to third-party processing plants and our treating facilities that include an acid gas reinjection well located in McMullen County, Texas.

The natural gas supply for our south Texas gathering systems is derived primarily from natural gas wells located in a mature basin that generally have long lives and predictable gas flow rates. The emerging Eagle Ford shale formation lies directly under our existing south Texas gathering system infrastructure.

One of our treating plants consists of inlet gas compression, a 60 MMcf/d amine treating unit, a 55 MMcf/d amine treating unit and a 40 ton (per day) liquid sulfur recovery unit. This plant removes hydrogen sulfide from the natural gas stream, recovers condensate, delivers pipeline quality gas at the plant outlet and reinjects acid gas. An additional 55 MMcf/d amine treating unit is currently inactive.

We own a 60 percent interest in a joint venture that includes a treating plant in Atascosa County with a 500 GPM amine treater, pipeline interconnect facilities, and approximately 13 miles of ten inch diameter pipeline. We operate this plant and the pipeline for the joint venture while our joint venture partner operates a lean gas gathering system in the Edwards Lime natural gas trend that delivers to this system.

West Texas Region. Our gathering system assets offer wellhead-to-market services to producers in Ward, Winkler, Reeves, and Pecos counties which surround the Waha Hub, one of Texas’ major natural gas market areas. As a result of the proximity of our system to the Waha Hub, the Waha gathering system has a variety of market outlets for the natural gas that we gather and process, including several major interstate and intrastate pipelines serving California, the mid-continent region of the United States and Texas natural gas markets. Natural gas exploration and production drilling in this area has primarily targeted productive zones in the Permian Delaware basin and Devonian basin. These basins are mature basins with wells that generally have long lives and predictable flow rates.

We offer producers four different levels of natural gas compression on the Waha gathering system, as compared to the two levels typically offered in the industry. By offering multiple levels of compression, our gathering system is often more cost-effective for our producers, since the producer is typically not required to pay for a level of compression that is higher than the level they require.

The Waha processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered in the Waha gathering system. This plant was constructed in 1965, and, due to recent upgrades to state-of-the-art cryogenic processing capabilities, is a highly efficient natural gas processing plant. The Waha processing plant also includes an amine treating facility which removes carbon dioxide and hydrogen sulfide from raw natural gas gathered before moving the natural gas to the processing plant. The acid gas is injected underground.

Mid-Continent Region. Our mid-continent region includes natural gas gathering systems located primarily in Kansas and Oklahoma. Our mid-continent gathering assets are extensive systems that gather, compress and

 

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dehydrate low-pressure gas from approximately 1,500 wells. These systems are geographically concentrated, with each central facility located within 90 miles of the others. We operate our mid-continent gathering systems at low pressures to maximize the total throughput volumes from the connected wells. Wellhead pressures are therefore adequate to allow for flow of natural gas into the gathering lines without the cost of wellhead compression.

Our mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, the Hugoton Basin in southwest Kansas and the Anadarko Basin in western Oklahoma. These mature basins have continued to provide generally long-lived, predictable production volume.

TRANSPORTATION OPERATIONS

Transportation. We own a 43 percent interest in HPC which, through RIGS, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system known as RIGS. The construction and development of the expansion of RIGS (“Haynesville Expansion Project”) was completed in January 2010 and added 1.1 Bcf/d of capacity and 14,200 horsepower of compression. In September 2009, HPC announced plans to construct a $47,000,000 pipeline extension of the Haynesville Expansion Project (the “Red River Lateral”). The Red River Lateral was also completed in January 2010, adding an additional 100 MMcf/d of capacity, bringing RIGS’ total capacity to 2.1 Bcf/d.

RIGS consists of an intrastate pipeline ranging from 4 to 42 inches in diameter that extends across north Louisiana from Caddo Parish to Franklin Parish and, with the completion of the Red River Lateral, extends into Red River Parish. In addition to the Haynesville Shale production, RIGS transports natural gas produced from the Vernon field, the Elm Grove field and the Sligo field. The transportation operations are located in areas that have experienced significant levels of drilling activity, providing RIGS with opportunities to access newly developed natural gas supplies.

Substantially all of the incremental capacity from Haynesville Expansion Project and Red River Lateral has been contracted to third parties under firm transportation agreements with 10-year terms, whereby approximately 85 percent of total revenues from these system expansions will be derived from reservation fees.

CONTRACT COMPRESSION OPERATIONS

The natural gas contract compression segment services include designing, sourcing, owning, insuring, installing, operating, servicing, repairing, and maintaining compressors and related equipment for which we guarantee our customers 98 percent mechanical availability for land installations and 96 percent mechanical availability for over-water installations. We focus on meeting the complex requirements of field-wide compression applications, as opposed to targeting the compression needs of individual wells within a field. These field-wide applications include compression for natural gas gathering, natural gas lift for crude oil production and natural gas processing. We believe that we improve the stability of our cash flow by focusing on field-wide compression applications because such applications generally involve long-term installations of multiple large horsepower compression units. Our contract compression operations are primarily located in Texas, Louisiana, Arkansas, and Pennsylvania.

 

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The following tables set forth certain information regarding contract compression’s third-party revenue generating horsepower as of December 31, 2009 and 2008.

 

     December 31, 2009

Horsepower Range

   Revenue Generating
Horsepower
   Percentage of
Revenue
Generating
Horsepower
    Number of Units

0-499

   65,397    9   361

500-999

   74,826    10   121

1,000+

   613,105          81   405
               
   753,328    100   887
               
     December 31, 2008

Horsepower Range

   Revenue Generating
Horsepower
   Percentage of
Revenue
Generating
Horsepower
    Number of Units

0-499

   59,288    7   351

500-999

   83,299    11   134

1,000+

   636,080          82   425
               
   778,667    100   910
               

CORPORATE AND OTHERS

Gulf States Transmission. Our interstate pipeline, owned and operated by GSTC, consists of 10 miles of 12 and 20 inch diameter pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. The pipeline has a FERC certificated capacity of 150 MMcf/d.

OUR CONTRACTS

The table below provides the margin by product and percentage for the years ended December 31, 2009 and 2008.

 

Margin by Product

   2009     2008  

Net Fee

       71       64

NGL

   20      18   

Gas

   4      10   

Condensate

   5      5   

Helium and Sulphur

   —        3   
            

Total

   100   100
            

Gathering and Processing Contracts. We contract with producers to gather raw natural gas from individual wells or central receipt points located near our gathering systems and processing plants. Following the execution of a contract with the producer, we connect the producer’s wells or central receipt points to our gathering lines through which the natural gas is delivered to a processing plant owned and operated by us or a third party. We obtain supplies of raw natural gas for our gathering and processing facilities under contracts having terms ranging from month-to-month to life of the lease. We categorize our processing contracts in increasing order of commodity price risk as fee-based, percentage-of-proceeds, or keep-whole contracts. For a description of our fee-based arrangements, percent-of-proceeds arrangements, and keep-whole arrangements, please read “Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Our Operations.”

 

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During the year ended December 31, 2009, purchases in our gathering and processing segment from one producer represented 23 percent of the cost of gas and liquids in our consolidated statement of operations.

We also perform a producer service function. We purchase natural gas from producers or gas marketers at receipt points or plant tailgates at an adjusted market price and sell the natural gas at market price.

Transportation Contracts. HPC, through RIGS, provides natural gas transportation services pursuant to contracts with natural gas shippers. These contracts are all fee-based. Generally, the transportation services are of two types: firm transportation and interruptible transportation. When RIG agrees to provide firm transportation service, it becomes obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation, the shipper pays a specified reservation charge, whether or not the capacity is utilized by the shipper, and in some cases the shipper also pays a commodity charge with respect to quantities actually shipped. When RIG agrees to provide interruptible transportation service, it becomes obligated to transport natural gas nominated and actually delivered by the shipper only to the extent that RIG has available capacity. The shipper pays no reservation charge for this service but pays a commodity charge for quantities actually shipped. RIG provides its transportation services for intrastate transportation under the negotiated terms of the contracts and under an operating statement that it has filed and maintains with the FERC with respect to transportation authorized under Section 311 of the NGPA.

Compression Contracts. We generally enter into a new contract with respect to each distinct application for which we will provide contract compression services. Our compression contracts typically have an initial term between one and five years, after which the contract continues on a month-to-month basis. Our customers generally pay a fixed monthly fee, or, in rare cases, a fee based on the volume of natural gas actually compressed. We are not responsible for acts of force majeure and our customers are generally required to pay our monthly fee for fixed fee contracts, or a minimum fee for throughput contracts, even during periods of limited or disrupted production. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessary lubricants, although certain fees and expenses are the responsibility of the customers under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity. We are also reimbursed by our customers for certain ancillary expenses such as trucking, crane and installation labor costs, depending on the terms agreed to in a particular contract.

COMPETITION

Gathering and Processing. We face strong competition in each region in acquiring new gas supplies. Our competitors in acquiring new gas supplies and in processing new natural gas supplies include major integrated oil companies, major interstate and intrastate pipelines and other natural gas gatherers that gather, process and market natural gas. Competition for natural gas supplies is primarily based on the reputation, efficiency and reliability of the gatherer and the pricing arrangements offered by the gatherer.

Many of our competitors have capital resources and control supplies of natural gas substantially greater than ours. Our major competitors for gathering and related services in each region include:

 

 

 

North Louisiana: CenterPoint Energy Field Services and DCP Midstream’s PELICO Pipeline, LLC (Pelico);

 

 

 

East Texas: Enbridge Energy Partners LP and Eagle Rock Energy Partners, L.P.;

 

 

 

South Texas: Enterprise Products Partners LP and DCP Midstream Partners, L.P;

 

 

 

West Texas: Southern Union Gas Services and Enterprise Products Partners LP; and

 

 

 

Mid-Continent: DCP Midstream Partners, L.P., ONEOK Energy Marketing and Trading, L.P., and Penn Virginia Corporation.

 

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Transportation. Competitors in natural gas transportation differentiate themselves by price of transportation, the nature of the markets accessible from a transportation pipeline and the type of service provided. In transporting natural gas across north Louisiana, HPC, through RIGS, typically receives gas from gathering facilities and delivers gas to intrastate and interstate markets. RIG competes with interstate and intrastate pipelines that have access to the same gathering facilities or production areas. RIG’s major competitors in the natural gas transportation business are DCP Midstream Partners, L.P., CenterPoint Energy Transmission, Gulf South Pipeline, L.P., Texas Gas Transmission, LLC and new entrants in north Louisiana such as Energy Transfer Partners LP, Enbridge Energy Partners LP, and Enterprise Products Partners LP.

Contract Compression. The natural gas contract compression services business is highly competitive. We face competition from large national and multinational companies with greater financial resources and, on a regional basis, from numerous smaller companies. Our main competitors in the natural gas contract compression business, based on horsepower, are Exterran Holdings, Inc., Compressor Systems, Inc., USA Compression, Valerus, and J-W Operating Company.

We believe that the superior mechanical availability of our standardized compressor fleet is the primary basis on which we compete and a significant distinguishing factor from our competition. All of our competitors attempt to compete on the basis of price. We believe our pricing has proven competitive because of the superior mechanical availability we deliver, the quality of our compression units, as well as the technical expertise we provide to our customers. We believe our focus on addressing customers’ more complex natural gas compression needs related primarily to field-wide compression applications differentiates us from many of our competitors who target smaller horsepower projects related to individual wellhead applications.

RISK MANAGEMENT

To manage commodity price and interest rate risks, we have implemented a risk management program under which we seek to:

 

 

 

match sales prices of commodities (especially natural gas liquids) with purchases under our contracts;

 

 

 

manage our portfolio of contracts to reduce commodity price risk;

 

 

 

optimize our portfolio by active monitoring of basis, swing, and fractionation spread exposure; and

 

 

 

hedge a portion of our exposure to commodity prices.

As a result of our gathering and processing contract portfolio, we derive a portion of our earnings from a long position in NGLs, natural gas and condensate, resulting from the purchase of natural gas for our account or from the payment of processing charges in kind. This long position is exposed to commodity price fluctuations in both the NGL and natural gas markets. Operationally, we mitigate this price risk by generally purchasing natural gas and NGLs at prices derived from published indices, rather than at a contractually fixed price and by selling natural gas and natural gas liquids under similar pricing mechanisms. In addition, we optimize the operations of our processing facilities on a daily basis, for example by rejecting ethane in processing when recovery of ethane as an NGL is uneconomical. We also hedge this commodity price risk by entering a series of swap contracts for individual NGLs, natural gas, and WTI crude oil. Our hedging position and needs to supplement or modify our position are closely monitored by the Risk Management Committee of the Board of Directors. Please read “Item 7A-Quantitative and Qualitative Disclosures About Market Risk” for information regarding the status of these contracts. As a matter of policy, we do not acquire forward contracts or derivative products for the purpose of speculating on price changes.

Our contract compression business does not have direct exposure to natural gas commodity price risk because we do not take title to the natural gas we compress and because the natural gas we use as fuel for our compressors is supplied by our customers without cost to us.

 

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REGULATION

Industry Regulation

Intrastate Natural Gas Pipeline Regulation. HPC owns RIGS, an intrastate pipeline regulated by the Louisiana Department of Natural Resources, Office of Conservation (DNR). The DNR is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Louisiana also has agencies that regulate transportation rates, service terms and conditions and contract pricing to ensure their reasonableness and to ensure that the intrastate pipeline companies that they regulate do not discriminate among similarly situated customers. RIG transports interstate natural gas in Louisiana for many of its shippers pursuant to Section 311 of the NGPA. To the extent that RIG transports natural gas in interstate service, its rates, terms and conditions of service are subject to the jurisdiction of FERC, including its non-discrimination requirements. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of such fair and equitable rates are subject to refund with interest. NGPA Section 311 rates deemed fair and equitable by FERC are generally analogous to the cost-based rates that FERC deems “just and reasonable” for interstate pipelines under the NGA. FERC has substantial enforcement authority to impose administrative, civil and criminal penalties, and to order the disgorgement of unjust profits for non-compliance.

In January 2010, RIG filed a petition with FERC to increase its maximum rates for Section 311 transportation services to recover the costs of operating RIGS, including the Haynesville Expansion Project and Red River Lateral. The rates are effective February 1, 2010, but subject to refund with interest.

FERC is continually proposing and implementing new rules and regulations affecting Section 311 transportation. FERC has adopted new regulations requiring certain major non-interstate pipelines to post on their internet websites receipt and delivery point capacities and scheduled flow information on a daily basis. These regulations are 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. Although these regulations are currently subject to petitions for review before the United States Court of Appeals for the District of Columbia Circuit, the posting requirements impose increased costs and administrative burdens on intrastate pipelines, including RIGS owned by HPC. FERC has also proposed regulations requiring intrastate pipelines providing NGPA Section 311 transportation service to submit to FERC and post quarterly transactional reports publicly. This would involve publicly disclosing the primary commercial terms of RIG’s contracts, including shipper name, contract length, rates charged, and points of receipt and delivery. Such regulations would impose additional regulatory burdens and costs on RIG and require the release of commercially-sensitive customer information. Since any new regulations would also be required of competitors providing Section 311 service, we do not believe new regulations would place RIG at a disadvantage vis-à-vis its competitors.

Interstate Natural Gas Pipeline Regulation. FERC also has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the pipeline owned by our subsidiary, GSTC. Under the NGA, rates charged for interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates are subject to refund with interest. GSTC holds a FERC-approved tariff setting forth cost-based rates, terms and conditions for services to shippers wishing to take interstate transportation service. FERC’s authority extends to:

 

 

 

rates and charges for natural gas transportation and related services;

 

 

 

certification and construction of new facilities;

 

 

 

extension or abandonment of services and facilities;

 

 

 

maintenance of accounts and records;

 

 

 

relationships between the pipeline and its energy affiliates;

 

 

 

terms and conditions of service;

 

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depreciation and amortization policies;

 

 

 

accounting rules for ratemaking purposes;

 

 

 

acquisition and disposition of facilities;

 

 

 

initiation and discontinuation of services;

 

 

 

prevention of market manipulation in connection with interstate sales, purchases, or transportation of natural gas; and

 

 

 

information posting requirements.

Any failure on our part to comply with the laws and regulations governing interstate transmission service could result in the imposition of administrative, civil and criminal penalties.

FERC is continually proposing and implementing new rules and regulations affecting interstate transportation. We do not believe that we will be affected by any such FERC action in a manner materially different than any other natural gas companies with which we compete.

Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of the FERC under the NGA. We own a number of natural gas pipelines that we believe meet the traditional tests that FERC has used to establish a pipeline’s status as a gatherer not subject to FERC’s interstate pipeline jurisdiction. The distinction between FERC-regulated transmission facilities and federally unregulated gathering facilities is the subject of substantial, on-going litigation, so the classification and regulation of one or more of our gathering systems may be subject to change based on future determinations by FERC, the courts or the U.S. Congress.

With the passage of the Energy Policy Act of 2005, FERC has expanded its oversight to energy market participants, including gathering pipelines, to increase transparency in interstate markets. Newly adopted transparency regulations require certain non-interstate pipelines, including gathering pipelines, to post on their Internet websites receipt and delivery point capacities and scheduled flow information on a daily basis. Although these regulations are currently subject to petitions for review before the United States Court of Appeals for the District of Columbia Circuit, these new requirements and future proposed regulations could impose increased costs and administrative burdens on our gathering companies.

State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and, in other instances, complaint-based rate regulation. We are subject to state ratable take and common purchaser statutes. The 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 that purchase gas to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another or one source of supply over another. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Natural gas gathering may receive greater regulatory scrutiny at the state level now that the FERC has allowed a number of interstate pipeline transmission companies to transfer formerly jurisdictional assets to gathering companies. For example, in 2006, the TRRC approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines that prohibit such entities from unduly discriminating in favor of their affiliates.

In addition, many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and

 

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services. Our gathering operations also may be subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules, ordinances and legislation pertaining to these matters may be considered or adopted from time to time at either the federal, state or local level. 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.

Regulation of NGL and Crude Oil Transportation. We have a pipeline in Louisiana that transports NGLs in interstate commerce pursuant to a FERC approved tariff. Under the ICA, the Energy Policy Act of 1992, and rules and orders promulgated thereunder, the transportation tariff is required to be just and reasonable and not unduly discriminatory or confer any undue preference. FERC has established an indexing system of transportation rates for oil, NGLs and other products that allows for an annual inflation based increase in the cost of transporting these liquids to shipper. Any failure on our part to comply with the laws and regulations governing interstate transmission of NGLs could result in the imposition of administrative, civil and criminal penalties and could have a material adverse effect on our results of operations.

Sales of Natural Gas and NGLs. Our ability to sell gas in interstate markets is subject to FERC authority and oversight. The price at which we buy and sell natural gas currently is not subject to federal regulation and, for the most part, is not subject to state regulation. The price at which we sell NGLs is not subject to state or federal 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 FERC and/or the CFTC.

The prices at which we sell natural gas are affected by many competitive factors, including the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC has also imposed new rules requiring whole-sale purchasers and sellers of natural gas to report certain aggregated annual volume and other information beginning in 2009.

We also have firm and interruptible 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 and the disgorgement of unjust profits.

Sales of Liquids. Sales of crude oil, natural gas, condensate and NGLs are not currently regulated. Prices of these products are set by the market rather than by regulation.

Anti-Market Manipulation Requirements. 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 CFTC also holds 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, NGLs and crude oil, 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 $1,000,000 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.

Anti-Terrorism Regulations. We may be subject to future anti-terrorism requirements of the DHS. The DHS has issued its National Infrastructure Protection Plan calling for broadened efforts to “reduce vulnerability, deter threats, and minimize the consequences of attacks and other incidents” as they relate to pipelines, processing

 

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facilities and other infrastructure. The precise parameters of DHS regulations and any related sector-specific requirements are not currently known, and there can be no guarantee that any final anti-terrorism rules that might be applicable to our facilities will not impose costs and administrative burdens on our operations.

Environmental Matters

General. Our operation of processing plants, pipelines and associated facilities, including compression, in connection with the gathering and processing of natural gas and the transportation of NGLs is subject to stringent and complex federal, state and local laws and regulations, including those governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of doing business, including our cost of planning, constructing and operating our plants, pipelines and other facilities. Included in our construction and operation costs are capital cost items necessary to maintain or upgrade our equipment and facilities to remain in compliance with environmental laws and regulations.

We have implemented procedures to ensure that all governmental environmental approvals for both existing operations and those under construction are updated as circumstances require. We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and that the cost of compliance with such laws and regulations will not have a material adverse effect on our business, results of operations and financial condition. We cannot be certain, however, that identification of presently unidentified conditions, more rigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

Hazardous Substances and Waste Materials. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances and waste materials into soils, groundwater and surface water and include measures to prevent, minimize or remediate contamination of the environment. These laws and regulations generally regulate the generation, storage, treatment, transportation and disposal of hazardous substances and waste materials and may require investigatory and remedial actions at sites where such material has been released or disposed. For example, CERCLA, also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to a release of a “hazardous substance” into the environment. These persons include the owner and operator of the site where a release occurred and companies that disposed or arranged for the disposal of the hazardous substance that has been released into the environment. Under CERCLA, these persons may be subject to joint and several liability, without regard to fault, for, among other things, the costs of investigating and remediating the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA and comparable state law also authorize the federal EPA, its state counterparts, and, in some instances, 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. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within that definition, and certain state law analogs to CERCLA, including the Texas Solid Waste Disposal Act, do not contain a similar exclusion for petroleum. We may be responsible under CERCLA or state laws for all or part of the costs required to clean up sites at which such substances or wastes have been disposed. We have not received any notification that we may be potentially responsible for cleanup costs under CERCLA or comparable state laws.

 

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We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal RCRA, and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements at many of our facilities because the minimal quantities of hazardous wastes generated there make us subject to less stringent management standards. From time to time, the EPA has considered the adoption of stricter handling, storage, and disposal standards for nonhazardous wastes, including crude oil and natural gas wastes. It is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly disposal requirements, or that the full complement of RCRA standards could be applied to facilities that generate lesser amounts of hazardous waste. Changes in applicable regulations may result in a material increase in our capital expenditures or plant operating and maintenance expense.

We currently own or lease sites that have been used over the years by prior owners and by us for natural gas gathering, processing and transportation. Solid waste disposal practices within the midstream gas industry have improved over the years with the passage and implementation of various environmental laws and regulations. Nevertheless, some hydrocarbons and wastes have been disposed of or released on or under various sites during the operating history of those facilities that are now owned or leased by us. Notwithstanding the possibility that these dispositions may have occurred during the ownership of these assets by others, these sites may be subject to CERCLA, RCRA and comparable state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or contamination (including soil and groundwater contamination) or to prevent the migration of contamination.

Assets Acquired from El Paso. Under the agreement pursuant to which our operating partnership acquired assets from El Paso Field Services LP and its affiliates in 2003, an escrow account of $9,000,000 relating to claims, including environmental claims, was established. After the time of this agreement, a Final Site Investigation Report was prepared. Based on this additional investigation, environmental issues were determined to exist with respect to a number of our facilities.

In January 2008, pursuant to authorization by the Board of Directors of the General Partner, the Partnership agreed to partially settle the El Paso environmental remediation claims. Under the settlement, El Paso agreed to clean up and obtain “no further action” letters from the relevant state agencies for three Partnership-owned facilities. El Paso is not obligated to clean up properties leased by the Partnership, but it has indemnified the Partnership for pre-closing environmental liabilities. All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved. In May 2008, the Partnership released all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations. This amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

West Texas Assets. A Phase I environmental study was performed on certain assets located in west Texas in connection with the pre-acquisition due diligence process in 2004. Most of the identified environmental contamination had either been remediated or was being remediated by the previous owners or operators of the properties. The aggregate potential environmental remediation costs at specific locations were estimated to range from $1,900,000 to $3,100,000. No governmental agency has required the Partnership to undertake these remediation efforts. Management believes that the likelihood that it will be liable for any significant potential remediation liabilities identified in the study is remote. Separately, the Partnership acquired an environmental pollution liability insurance policy in connection with the acquisition to cover any undetected or unknown pollution discovered in the future. The policy covers clean-up costs and damages to third parties, and has a 10-year term (expiring 2014) with a $10,000,000 limit subject to certain deductibles. No claims have been made against the Partnership with respect to environmental issues at the west Texas assets or under the policy.

Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants, 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

 

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facilities, such as our processing plants and compression facilities, expected to produce air emissions or to result in the increase of existing air emissions, that we obtain and strictly comply with air permits containing various emissions and operational limitations, or that we utilize specific emission control technologies to limit emissions. We 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. In addition, our processing plants, pipelines and compression facilities are subject to increasingly stringent regulations, including regulations that require the installation of control technology or the implementation of work practices to control hazardous air pollutants. Moreover, the Clean Air Act requires an operating permit for major sources of emissions and this requirement applies to some of our facilities. We believe that our operations are in substantial compliance with the federal Clean Air Act and comparable state laws.

Clean Water Act. The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including natural gas liquid-related wastes, into waters of the United States. Pursuant to the Clean Water Act and similar state laws, a NPDES, or state permit, or both, must be obtained to discharge pollutants into federal and state waters. In addition, the Clean Water Act and comparable state laws require that individual permits or coverage under general permits be obtained by subject facilities for discharges of storm water runoff. We believe that we are in substantial compliance with Clean Water Act permitting requirements as well as the conditions imposed thereunder, and that our continued compliance with such existing permit conditions will not have a material adverse effect on our business, financial condition, or results of operations.

Endangered Species Act. The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitat. While we have no reason to believe that we operate in any area that is currently designated as a habitat for endangered or threatened species, the discovery of previously unidentified endangered species, or the designation of additional species as endangered or threatened, could cause us to incur additional costs or to become subject to expansion or operating restrictions or bans in the affected areas.

Climate Change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climate changes. In response to such studies, President Obama has expressed support for and Congress is considering a variety of legislation to reduce emissions of greenhouse gases. Two of the bills, H.R. 2454 and S. 1733, employ a market-based cap-and-trade program, among other provisions, to reduce over time the emissions of greenhouse gases. The US House of Representatives approved H.R. 2454 on June 25, 2009. The Senate Environment and Public Works Committee adopted S. 1733 on November 5, 2009, but the bill has not yet been presented to the Senate for a vote. A cap-and-trade program could impose on us costs associated with the purchase of allowances or credits or costs associated with additional controls to manage emissions from our existing sources. An alternative bill, the Carbon Limits and Energy for America’s Renewal Act (“CLEAR”), was introduced in the Senate on December 9, 2009, and proposes to regulate the amount of fossil fuel carbon (defined to include natural gas) that producers and importers can introduce into domestic commerce. If enacted, CLEAR would require an entity in the business of producing fossil carbon to purchase the right to sell or otherwise place fossil carbon into commerce in the United States and also would reduce over time the total amount of fossil carbon that could be sold into domestic commerce. 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 greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas 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, such as refineries or gas processing plants, to acquire and, on an annual basis, surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations ( e.g. , compressor stations) or from the combustion of fuels ( e.g. , natural gas) we process.

In response to the United States Supreme Court’s holding in the 2007 decision, Massachusetts, et al. v. EPA (that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act ), in December 2009,

 

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EPA issued its Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (“Endangerment Finding”) ”), which found that greenhouse gas emissions endanger the public health and welfare and that the combined emissions of greenhouse gases from new motor vehicles contribute to global climate change. The Endangerment Finding does not itself impose any requirements on industry or other entities. It does, however, pave the way for EPA to finalize proposed greenhouse gas emission standards for motor vehicle sources which, in turn, could trigger stationary source controls under the Clean Air Act. Several parties have requested review of the Endangerment Finding with the U.S. Court of Appeals for the D.C. Circuit, but we cannot predict the outcome of the court’s review. In contemplation of the regulation of greenhouse gases emissions from stationary sources, in September 2009 EPA proposed new “applicability thresholds” for greenhouse gas emissions under the Clean Air Act’s Prevention of Significant Deterioration and Title V Operating Permit programs (“Tailoring Rule”). If promulgated as proposed, the Tailoring Rule would impose additional permitting requirements and the installation of “best available control technology” on new or modified stationary sources that emit more than 25,000 tons of carbon dioxide equivalent emissions annually. Any regulation of greenhouse gas emissions from stationary sources could apply to our processing, treating compression and pipeline facilities.

In addition, on January 19, 2010, EPA published a proposed rule that would reduce the NAAQS for ozone set in 2008 from 0.075 parts per million (“ppm”) to within the range of 0.060 to 0.070 ppm. Areas within states that we operate may not comply with the proposed NAAQS for ozone and, for those areas of nonattainment, states may adopt plans, known as State Implementation Plans, which could require new and modified sources of emissions to demonstrate compliance with allowable limits and may impose additional controls on our existing sources of ozone emissions.

It is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, but any such future laws and regulations could result in a potential decline in the production of natural gas, increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the natural gas we gather and process.

Employee Health and Safety. We are subject to the requirements of the federal 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 information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, recordkeeping requirements, and monitoring of occupational exposure to regulated substances.

Safety Regulations. Those pipelines through which we transport mixed NGLs (exclusively to other NGL pipelines) are subject to regulation by the DOT, under the HLPSA, relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA requires any entity that owns or operates liquids pipelines to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to submit certain reports and provide other information as required by the Secretary of Transportation. We believe our liquids pipelines are in substantial compliance with applicable HLPSA requirements.

Our interstate, intrastate and certain of our gathering pipelines are also are subject to regulation by the DOT under the NGPSA, which covers natural gas, crude oil, carbon dioxide, NGLs and petroleum products pipelines, and under the Pipeline Safety Improvement Act of 2002, as amended. Pursuant to these authorities, the DOT 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. The DOT’s integrity management rules establish requirements relating to the design, installation, testing, construction, operation, inspection, replacement and management of pipeline facilities. We believe that our pipeline operations are in substantial compliance with applicable NGPSA requirements.

 

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The states administer federal pipeline safety standards under the NGPSA and have the authority to conduct pipeline inspections, to investigate accidents, and to oversee compliance and enforcement, safety programs, and record maintenance and reporting. Congress, the DOT and individual states may pass additional pipeline safety requirements, but such requirements, if adopted, would not be expected to affect us disproportionately relative to other companies in our industry.

The DOT has recently proposed new regulations as directed by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The proposed rules require operators of hazardous liquids pipelines, gas pipelines and LNG facilities with at least one control room to develop, implement and submit written control room management procedures and to conduct baseline point by point verifications and periodic testing of a pipeline’s SCADA system. When adopted, the new regulations may increase regulatory burdens and administrative costs for the Partnership.

TCEQ Notice of Enforcement. In February 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas. The NOE alleged that, between March 9, 2006, and May 8, 2007, this plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence. In January 2010, the TCEQ notified us in writing that it had concluded that there had been no violation and that the TCEQ would take no further action.

EMPLOYEES

As of December 31, 2009, our General Partner employed 761 employees, of whom 520 were field operating employees and 241 were mid-and senior-level management and staff. None of these employees are represented by a labor union and there are no outstanding collective bargaining agreements to which our General Partner is a party. Our General Partner believes that it has good relations with its employees.

AVAILABLE INFORMATION

We file annual and quarterly financial reports, current-event reports as well as interim updates of a material nature to investors with the Securities and Exchange Commission. You may read and copy any of these materials at the SEC’s Public Reference Room at 100 F. Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room is available by calling the SEC at 1-800-SEC-0330. Alternatively, the SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of that site is http://www.sec.gov.

We make our SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through its Internet website located at http://www.regencyenergy.com. Our annual reports are filed on Form 10-K, our quarterly reports are filed on Form 10-Q, and current-event reports are filed on Form 8-K; we also file amendments to reports filed or furnished pursuant to Section 13(a) or Section 15(d) of the Exchange Act. References to our website addressed in this report are provided as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this report.

 

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Item 1A. Risk Factors

RISKS RELATED TO OUR BUSINESS

We may not have sufficient cash from operations to enable us to pay our current quarterly distribution following the establishment of cash reserves and payment of fees and expenses, including reimbursement of fees and expenses of our general partner.

We may not have sufficient available cash from operating surplus each quarter to pay our MQD. The amount of cash we can distribute to our unitholders depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

 

 

prevailing economic conditions;

 

 

 

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

 

 

 

the prices of, level of, production of, and demand for natural gas and NGLs;

 

 

 

the volumes of natural gas we gather, process and transport; and

 

 

 

the amounts of our operating costs, including reimbursement of fees and expenses of our general partner.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

 

 

 

our debt service requirements;

 

 

 

fluctuations in our working capital needs;

 

 

 

our ability to borrow funds and access capital markets;

 

 

 

restrictions contained in our debt agreements;

 

 

 

the level of capital expenditures we make;

 

 

 

the cost of acquisitions, if any; and

 

 

 

the amount of cash reserves established by our General Partner.

You should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, which will be affected by non-cash items and not solely on profitability. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not be able to make cash distributions during periods when we record net earnings for financial accounting purposes.

Natural gas, NGLs and other commodity prices are volatile, and an unfavorable change in these prices could adversely affect our cash flow and operating results.

We are subject to risks due to frequent and often substantial fluctuations in commodity prices. NGLs prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and this volatility could continue. Volatility in crude oil and natural gas prices can impact our customers’ activity levels and spending for our products and services, as well as our margins under our keep-whole and percentage-of-proceeds natural gas gathering and processing contracts. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuates with changes in market and economic conditions and other factors, including:

 

 

 

the level of domestic oil and natural gas production;

 

 

 

the availability of imported oil and natural gas;

 

 

 

actions taken by foreign oil and gas producing nations;

 

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

 

 

 

the availability of local, intrastate and interstate transportation systems;

 

 

 

the availability and marketing of competitive fuels;

 

 

 

the impact of energy conservation efforts; and

 

 

 

the extent of governmental regulation and taxation.

Our natural gas gathering and processing businesses operate under two types of contractual arrangements that expose our cash flows to increases and decreases in the price of natural gas and NGLs: percentage-of-proceeds and keep-whole arrangements. Under percentage-of-proceeds arrangements, we generally purchase natural gas from producers and retain from the sale an agreed percentage of pipeline-quality gas and NGLs resulting from our processing activities (in cash or in-kind) at market prices. Under keep-whole arrangements, we receive the NGLs removed from the natural gas during our processing operations as the fee for providing our services in exchange for replacing the thermal content removed as NGLs with a like thermal content in pipeline-quality gas or its cash equivalent. Under these types of arrangements our revenues and our cash flows increase or decrease as the prices of natural gas and NGLs fluctuate. The relationship between natural gas prices and NGL prices may also affect our profitability. When natural gas prices are low relative to NGLs prices, it is more profitable for us to process natural gas under keep-whole arrangements. When natural gas prices are high relative to NGLs prices, it is less profitable for us and our customers to process natural gas both because of the higher value of natural gas and of the increased cost (principally that of natural gas as a feedstock and a fuel) of separating the mixed NGLs from the natural gas. As a result, we may experience periods in which higher natural gas prices relative to NGL prices reduce our processing margins or reduce the volume of natural gas processed at some of our plants.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new supplies of natural gas, which involves factors beyond our control. Any decrease in supplies of natural gas in our areas of operation could adversely affect our business and operating results.

Our gathering and processing and transportation pipeline systems are dependent on the level of production from natural gas wells that supply our systems and from which production will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase through-put volume levels on our gathering and transportation pipeline systems and the asset utilization rates at our natural gas processing plants, we must continually obtain new supplies. The primary factors affecting our ability to obtain new supplies of natural gas and attract new customers to our assets are: the level of successful drilling activity near our systems and our ability to compete with other gathering and processing companies for volumes from successful new wells.

The level of natural gas drilling activity is dependent on economic and business factors beyond our control. The primary factor that impacts drilling decisions is natural gas prices. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the fields served by our gathering and processing facilities and pipeline transportation systems, which would lead to reduced utilization of these assets. Other factors that impact production decisions include producers’ capital budget limitations, which have become more constrained in this past year, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes. For example, companion Senate and House bills to amend the Safe Drinking Water Act were introduced in Congress in June 2009. The proposed legislation would require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could result in a decrease in our customers’ exploration and production activities, resulting in lower volumes of natural gas production, which could result in a decline in the demand for our services.

 

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Because of these factors, even if additional natural gas reserves were discovered in areas served by our assets, producers may choose not to develop those reserves. If we were not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, through-put volumes on our pipelines and the utilization rates of our processing facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition.

Our natural gas contract compression operations significantly depend upon the continued demand for and production of natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, demand for energy, and availability of alternative energy sources. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of production activity and result in a decline in the demand for our contract compression services and products. Lower natural gas prices or crude oil prices over the long-term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our natural gas contract compression services. Additionally, production from natural gas sources such as longer-lived tight sands, shales and coalbeds constitute an increasing percentage of our compression services business. Such sources are generally less economically feasible to produce in lower natural gas price environments, and a reduction in demand for natural gas or natural gas lift for crude oil may cause such sources of natural gas to be uneconomic to drill and produce, which could in turn negatively impact the demand for our compression services.

Many of our customers’ drilling activity levels and spending for transportation on our pipeline system may be impacted by the current deterioration in commodity prices and the credit markets.

Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Recently, there has been a significant decline in the credit markets and the availability of credit. Any combination of a reduction of cash flow resulting from declines in natural gas prices, a reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ spending for natural gas drilling activity, which could result in lower volumes being transported on our pipeline system. A significant reduction in drilling activity could have a material adverse effect on our operations.

We depend on certain key producers and other customers for a significant portion of our supply of natural gas and contract compression revenue. The loss of, or reduction in, any of these key producers or customers could adversely affect our business and operating results.

We rely on a limited number of producers and other customers for a significant portion of our natural gas supplies and our contracts for compression services. These contracts have terms that range from month-to-month to life of lease. As these contracts expire, we will have to negotiate extensions or renewals or replace the contracts with those of other suppliers. We may be unable to obtain new or renewed contracts on favorable terms, if at all. The loss of all or even a portion of the volumes of natural gas supplied by these producers and other customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, and financial condition.

We own a 43 percent equity interest in HPC and we do not exercise control over HPC.

We own a 43 percent ownership interest in HPC and we have the right to appoint one member of the four member management committee. Each member has a vote equal to the sharing ratio of the partner that appointed such member. Accordingly, we do not exercise control over HPC. In addition, HPC’s partnership agreement contains standard supermajority voting provisions and also requires that the following actions, among other things, be approved by at least 75 percent of the members of the management committee: merger or consolidation of the joint venture, sale of all or substantially all of the assets of the joint venture, determination to raise additional capital, determining the amount of available cash, causing the joint venture to terminate the master services agreement, approval of any budget and entry into material contracts.

 

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We may be required to make additional capital contributions to HPC.

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

Our contract compression segment depends on particular suppliers and is vulnerable to parts and equipment shortages and price increases, which could have a negative impact on our results of operations.

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc. for engines, Air-X-Changers for coolers, and Ariel Corporation for compressors and frames. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on two vendors, Spitzer Industries Corp. and Standard Equipment Corp., to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships. In addition, since we expect any increase in component prices for compression equipment or packaging costs will be passed on to us, a significant increase in their pricing could have a negative impact on our results of operations.

In accordance with industry practice, we do not obtain independent evaluations of natural gas reserves dedicated to our gathering systems. Accordingly, volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate, which could adversely affect our business and operating results.

We do not obtain independent evaluations of natural gas reserves connected to our gathering 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 lives of such reserves. If the total reserves or estimated lives of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional sources of natural gas, then the volumes of natural gas gathered on our gathering systems in the future could be less than we anticipate. A decline in the volumes of natural gas gathered on our gathering systems could have an adverse effect on our business, results of operations, and financial condition.

In our gathering and processing operations, we purchase raw natural gas containing significant quantities of NGLs, process the raw natural gas and sell the processed gas and NGLs. If we are unsuccessful in balancing the purchase of raw natural gas with its component NGLs and our sales of pipeline quality gas and NGLs, our exposure to commodity price risks will increase.

We purchase from producers and other customers a substantial amount of the natural gas that flows through our natural gas gathering and processing systems and our transportation pipeline for resale to third parties, including natural gas marketers and utilities. We may not be successful in balancing our purchases and sales. In addition, a producer could fail to deliver promised volumes or could deliver volumes in excess of contracted volumes, a purchaser could purchase less than contracted volumes, or the natural gas price differential between the regions in which we operate could vary unexpectedly. Any of these actions could cause our purchases and sales not to be balanced. If our purchases and sales are not balanced, we will face increased exposure to commodity price risks and could have increased volatility in our operating results.

Our results of operations and cash flow may be adversely affected by risks associated with our hedging activities.

In performing our functions in our gathering and processing segment, we are a seller of natural gas and NGLs and are exposed to commodity price risk associated with downward movements in commodity prices. As a result of the volatility of commodity prices and interest rates, we have executed swap contracts settled against ethane, propane, normal butane, isobutane, natural gas, natural gasoline and west Texas intermediate crude market prices and interest rates. We continually monitor our hedging and contract portfolio and expect to adjust

 

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our hedge position as conditions warrant. For more information about our risk management activities, please read “Item 7A—Quantitative and Qualitative Disclosures about Market Risk.” Even though our management monitors our hedging activities, these activities can result in substantial losses. Such losses could occur under various circumstances, including any circumstance in which a counterparty does not perform its obligations under the applicable hedging arrangement, the hedging arrangement is imperfect, or our hedging policies and procedures are not followed or do not work as planned.

In addition, proposed derivatives legislation in the U.S. Congress would impose limits, substantial costs and burdens on participants in the over-the-counter derivatives markets, which could restrict our use of hedges in the future and adversely affect our cash flows.

To the extent that we intend to grow internally through construction of new, or modification of existing, facilities, we may not be able to manage that growth effectively, which could decrease our cash flow and adversely affect our results of operations.

A principal focus of our strategy is to continue to grow by expanding our business both internally and through acquisitions. Our ability to grow internally will depend on a number of factors, some of which will be beyond our control. We may not be able to finance the construction or modifications on satisfactory terms. In general, the construction of additions or modifications to our existing systems, and the construction of new midstream assets involve numerous regulatory, environmental, political and legal uncertainties beyond our control. Any project that we undertake may not be completed on schedule, at budgeted cost or at all. Construction may occur over an extended period, and we are not likely to receive a material increase in revenues related to such project until it is completed. Moreover, our revenue may not increase immediately upon the completion of construction because the anticipated growth in gas production that the project was intended to capture does not materialize, our estimates of the growth in production prove inaccurate or for other reasons. For example, producers in the area may decrease their activity levels in the area near our Haynesville Expansion Project due to the declines in the price for natural gas. To the extent producers in the area are unable to execute their expected drilling programs, the return on our investment from this project may not be as attractive as we anticipate. For any of these reasons, newly constructed or modified midstream facilities may not generate our expected investment return and that, in turn, could adversely affect our cash flows and results of operations. In addition, our ability to undertake to grow in this fashion will depend on our ability to hire, train, and retain qualified personnel to manage and operate these facilities when completed.

We may have difficulty financing our planned capital expenditures, which could adversely affect our results and growth.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including borrowings under our credit facility and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have been distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and current weak economic conditions have affected, and will likely continue to affect, our ability to obtain funding.

The availability of funds from the debt and equity markets generally has diminished. Also, as a result of concerns about the stability of financial markets generally and the solvency of counterparties specifically, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity at all or on terms similar to our current debt and reduced and, in some cases, ceased to provide funding to borrowers.

In addition, because of the recent downturn in the financial markets, including the issues surrounding the solvency of many institutional lenders and the recent failure of several banks, our ability to obtain capital from

 

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our credit facility may be impaired. For example, as a result of Lehman Brothers Holding, Inc., or Lehman, filing a petition under Chapter 11 of the U.S. Bankruptcy Code, a subsidiary of Lehman that is a committed lender under our credit facility has declined requests to honor its commitment to lend under our credit facility. As of December 31, 2009, the unfunded commitment from Lehman was $10,675,000, thereby effectively reducing the amount available to us under our credit facility to $889,325,000. We may be unable to utilize the full borrowing capacity under our credit facility if other lenders are not willing to provide additional funding to make up the portion of the credit facility commitments that Lehman’s subsidiary has refused to fund or if any of the remaining committed lenders is unable or unwilling to fund their respective portion of any funding request we make under our credit facility.

Our leverage may limit our ability to borrow additional funds, make distributions, comply with the terms of our indebtedness or capitalize on business opportunities.

Our leverage is significant in relation to our partners’ capital. Our debt to capital ratio, calculated as total debt divided by the sum of total debt and partners’ capital, as of December 31, 2009 was 44 percent. We will be prohibited from making cash distributions during an event of default under any of our indebtedness, and, in the case of the indenture under which our senior notes were issued, the failure to maintain a prescribed ratio of consolidated cash flows (as defined in the indenture) to interest expense. Various limitations in our credit facility, as well as the indenture for our senior notes, may reduce our ability to incur additional debt, to engage in some transactions and to capitalize on business opportunities. Any subsequent refinancing of our current indebtedness or any new indebtedness could have similar or greater restrictions.

Our leverage may adversely affect our ability to fund future working capital, capital expenditures and other general partnership requirements, future acquisition, construction or development activities, or otherwise realize fully the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness. Our leverage may also make our results of operations more susceptible to adverse economic and industry conditions by limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate and may place us at a competitive disadvantage as compared to our competitors that have less debt.

Increases in interest rates could adversely impact our unit price and our ability to issue additional equity, in order to make acquisitions, to reduce debt, or for other purposes.

The interest rate on our senior notes is fixed and the loans outstanding under our credit facility bear interest at a floating rate. Interest rates on future credit facilities and debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, the market price for our units will be affected by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse effect on our unit price and our ability to issue additional equity in order to make acquisitions, to reduce debt or for other purposes.

Because we distribute all of our available cash to our unitholders, our future growth may be limited.

Since we will distribute all of our available cash to our unitholders, subject to the limitations on restricted payments contained in the indenture governing our senior notes and our credit facility, we will depend on financing provided by commercial banks and other lenders and the issuance of debt and equity securities to finance any significant internal organic growth or acquisitions. If we are unable to obtain adequate financing from these sources, our ability to grow will be limited.

 

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Our interstate gas transportation operations, including Section 311 service performed by our intrastate pipelines, our sales of gas in interstate commerce, and our shipment of gas on interstate pipelines are subject to FERC regulation; failure to comply with applicable regulation, future changes in regulations or policies, or the establishment of more onerous terms and conditions applicable to natural gas transportation service could adversely affect our business.

FERC has broad regulatory authority over the business and operations of interstate natural gas pipelines, such as the pipeline owned by our subsidiary, GSTC. GSTC holds a FERC-approved tariff setting forth cost- based rates, terms and conditions for services to shippers wishing to take interstate transportation service. Under the NGA, rates charged for, and the terms and conditions of service of, interstate natural gas transmission must be just and reasonable, and amounts collected in excess of just and reasonable rates may be subject to refund with interest. In addition, FERC regulates the rates, terms and conditions of service with respect to Section 311 transportation service provided by RIG. FERC has authority to alter its rules, regulations and policies governing service provided by interstate pipelines and intrastate pipelines providing Section 311 services. We cannot give any assurance regarding the likely future regulations under which GSTC or RIG will operate their interstate transportation businesses or the effect such regulation could have on our businesses or results of operations. In addition, FERC also has broad authority to require compliance with its rules and regulations and to prohibit and penalize manipulative behavior that affects markets. Since our gathering and processing businesses sell natural gas in interstate commerce and ship gas on interstate pipelines, these activities are subject to FERC oversight. Any failure on our part to comply with applicable FERC-administered statutes, rules, regulations and orders could result in the imposition of administrative, civil and/or criminal penalties, or both, as well as increased operational requirements or prohibitions.

As limited partnership entities, neither we nor our regulated pipelines, including RIGS, may be able to include a full tax allowance in calculating our costs-of-service for rate-making purposes.

Under current policy applied under the NGA and Section 311, FERC permits regulated gas pipelines to include, in the cost-of-service used as the basis for calculating the pipeline’s regulated rates, a tax allowance reflecting the actual or potential income tax liability on pipeline income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by FERC on a case-by-case basis, and the pipeline is required to demonstrate that such potential income tax liability exists. In connection with its January 28, 2010 Section 311 rate case (see below), RIG may be required to demonstrate the extent to which inclusion of an income tax allowance in its cost-of-service is permitted under the current income tax allowance policy. Although FERC’s policy is generally favorable for pipelines that are organized as, or owned by, tax-pass-through entities, application of the policy in individual rate cases still entails rate risk due to the case-by-case review requirement. The specific terms and application of that policy remain subject to future refinement or change by FERC and the courts. Moreover, we cannot guarantee that this policy will not be altered in the future.

There are uncertainties in the calculation of the return on equity that FERC will authorize a pipeline to include in its cost-of-service.

An important part of the determination of rates by FERC is the establishment of an authorized return on equity. FERC currently calculates a range of potential returns, based on a discounted cash flow analysis of companies included in a proxy group, and then determines where a pipeline’s risks require it to be placed within this range. FERC policy also currently allows the inclusion of master limited partnerships, or MLPs, in proxy groups used to calculate the appropriate returns on equity under FERC’s discounted cash flow analysis, but FERC limits recognition of certain MLP earnings and allows case-by-case determination by FERC of the appropriateness of any MLP, or indeed any stock corporation, proposed as a member of the pipeline's proxy group.

 

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A change in the level of regulation or the jurisdictional characterization of some of our assets or business activities by federal, state or local regulatory agencies could affect our operations and revenues.

Our natural gas gathering, processing and intrastate transportation operations are generally exempt from FERC regulation under the NGA, but FERC regulation still affects these businesses and the markets for products derived from these businesses. With the passage of the Energy Policy Act of 2005 (EPACT 2005), FERC has expanded its oversight of natural gas purchasers, natural gas sellers, gatherers, intrastate pipelines and shippers on FERC regulated pipelines by imposing new market monitoring and market transparency rules and rules prohibiting manipulative behavior. In addition, EPACT 2005 substantially increased FERC’s penalty authority. In recent years, FERC has adopted new rules requiring increased reporting by purchasers and sellers of natural gas, intrastate pipelines and gathering systems of certain information, and in 2009, FERC issued a notice of proposed rulemaking seeking comments on proposed increased transactional reporting requirements for intrastate pipelines. We cannot predict the outcome of the rulemaking proceeding or how FERC will approach future matters such as pipeline rates and rules and policies that may affect purchases or sales of natural gas or rights of access to natural gas transportation capacity.

In addition, the distinction between FERC-regulated interstate transmission service, on one hand, and intrastate transmission or federally unregulated gathering services, on the other hand, is the subject of regular litigation at FERC and in the courts and of policy discussions at FERC. In such circumstances, the classification and regulation of some of our gathering or our intrastate transportation pipelines may be subject to change based on future determinations by FERC, the courts, or Congress. Such a change could result in increased regulation by FERC, which could adversely affect our business.

Other state and local regulations also affect our business. Our gathering pipelines are subject to ratable take and common purchaser statutes in states in which we operate. Ratable take statutes generally require gatherers to take, without undue discrimination, oil or natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes restrict our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states. Many states in which we operate have adopted complaint-based regulation of natural gas gathering activities, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination.

Any new laws, rules, regulations or orders could result in additional compliance costs and/or requirements, which could adversely affect our business. If we fail to comply with any new or existing laws, rules, regulations, laws or orders, we could be subject to administrative, civil and/or criminal penalties, or both, as well as increased operational requirements or prohibitions.

Our ability to recover the costs of the Haynesville Expansion Project will depend upon RIG’s success in recovering these costs in a new rate proceeding with the Federal Energy Regulatory Commission and under the contracts with shippers.

The expansion phase of RIGS in North Louisiana was placed in service on January 27, 2010. At that time, RIG filed and implemented revised rates with FERC, the design of which will reflect the costs of and contracts for the use of this expansion capacity, and FERC may elect to review the rates under Section 311 of the Natural Gas Policy Act. The ability of RIG to charge rates that allow it to recover these costs, including a return on its capital, will depend on the outcome of any rate proceeding. We cannot assure you that RIG will be successful in such a proceeding. If FERC requires adjustments, including potential refunds, to the revised transportation rate, or if any contract rates to which RIG has agreed are below the maximum rates we otherwise could charge, our cash flows and ability to make distributions may be adversely affected.

 

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On January 28, 2010, RIG filed a rate case with FERC to implement significantly increased maximum rates for Section 311 transportation services provided by RIG effective February 1, 2010, to recover the costs of operating the RIGS pipeline system. The rate case reflects a substantial increase in the rate base of RIG, as well as increased costs, including return and income taxes, arising from the Haynesville Expansion Project and Red River Lateral. FERC will review the rates to determine whether they are fair and equitable and not in excess of an amount reasonably comparable to the rates that interstate pipelines would be permitted to charge for providing similar services. While RIG’s shippers are subject, in large part, to fixed or capped rates, FERC may still undertake a comprehensive review of the new rates and RIG’s operations and terms of service. FERC has the statutory authority to require a refund, with interest, of RIG’s rates from February 1, 2010. The timing and outcome of this proceeding is uncertain, and it could have a material adverse affect on HPC, the owner of RIGS, and our results of operations and business through our 43 percent interest in HPC.

We may be unable to integrate successfully the operations of future acquisitions with our operations, and we may not realize all the anticipated benefits of the past and any future acquisitions.

Integration of acquisitions with our business and operations is a complex, time consuming, and costly process. Failure to integrate acquisitions successfully with our business and operations in a timely manner may have a material adverse effect on our business, financial condition, and results of operations. We cannot assure you that we will achieve the desired profitability from past or future acquisitions. In addition, failure to assimilate future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions involve numerous risks, including:

 

 

 

operating a significantly larger combined organization and adding operations;

 

 

 

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

 

 

 

the risk that natural gas reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

 

 

 

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

 

 

 

the diversion of management’s attention from other business concerns;

 

 

 

the failure to realize expected profitability, growth or synergies and cost savings;

 

 

 

properly assessing and managing environmental compliance;

 

 

 

coordinating geographically disparate organizations, systems, and facilities; and

 

 

 

coordinating or consolidating corporate and administrative functions.

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. If we consummate any future acquisition, our capitalization and results of operation may change significantly, 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 industry is highly competitive, and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in each of our areas of operations. Some of our competitors are large oil, natural gas, gathering and processing and natural gas pipeline companies that have greater financial resources and access to supplies of natural gas than we do. In addition, our customers who are significant producers or consumers of NGLs may develop their own processing facilities in lieu of using ours. Similarly, competitors may establish new connections with pipeline systems that would create additional competition for services that we provide to our customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors.

 

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The natural gas contract compression business is highly competitive, and there are low barriers to entry for individual projects. In addition, some of our competitors are large national and multinational companies that have greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer or more powerful compressor fleets that would create additional competition for us. In addition, our customers that are significant producers of natural gas and crude oil may purchase and operate their own compressor fleets in lieu of using our natural gas contract compression services. All of these competitive pressures could have a material adverse effect on our business, results of operations, and financial condition.

Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

Users of our pipelines are dependent upon connections to and from third-party pipelines to receive and deliver natural gas and NGLs. Any reduction in the capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes being transported in our pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines could be reduced, which could also reduce volumes transported in our pipelines. Any reduction in volumes transported in our pipelines would adversely affect our revenue and cash flow.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. Many of our customers finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices, a reduction in borrowing bases under reserve based credit facilities (resulting from a decline in commodity prices) and the lack of availability of debt or equity financing may result in a significant reduction in our customers’ liquidity and ability to make payment or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

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 and financial results could be adversely affected.

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

 

 

 

damage to our gathering and processing facilities, pipelines, related equipment and surrounding properties caused by tornadoes, floods, hurricanes, fires and other natural disasters and acts of terrorism;

 

 

 

inadvertent damage from construction and farm equipment;

 

 

 

leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a result of the malfunction of pipelines, measurement equipment or facilities at receipt or delivery points;

 

 

 

fires and explosions;

 

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weather related hazards, such as hurricanes and extensive rains which could delay the construction of assets and extreme cold which can cause freezing of pipelines, limiting throughput; and

 

 

 

other hazards, including those associated with high-sulfur content, or sour gas, such as an accidental discharge of hydrogen sulfide gas, that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury 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. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not insured against all environmental events that might occur. If a significant accident or event occurs that is not insured or fully insured, it could adversely affect our operations and financial condition.

Failure of the gas that we ship on our pipelines to meet the specifications of interconnecting interstate pipelines could result in curtailments by the interstate pipelines.

The markets to which the shippers on our pipelines ship natural gas include interstate pipelines. These interstate pipelines establish specifications for the natural gas that they are willing to accept, which include requirements such as hydrocarbon dewpoint, temperature, and foreign content including water, sulfur, carbon dioxide, and hydrogen sulfide. These specifications vary by interstate pipeline. If the total mix of natural gas shipped by the shippers on our pipeline fails to meet the specifications of a particular interstate pipeline, it may refuse to accept all or a part of the natural gas scheduled for delivery to it. In those circumstances, we may be required to find alternative markets for that gas or to shut-in the producers of the non-conforming gas, potentially reducing our through-put volumes or revenues.

We may incur significant costs and liabilities as a result of pipeline integrity management program testing and any related pipeline repair, or preventative or remedial measures.

The DOT has adopted regulations requiring pipeline operators to develop integrity management programs for transportation pipelines and certain gathering lines located where a leak or rupture could do the most harm in “high consequence areas.” The regulations require operators to:

 

 

 

perform ongoing assessments of pipeline integrity;

 

 

 

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

 

 

 

improve data collection, integration and analysis;

 

 

 

repair and remediate the pipeline as necessary; and

 

 

 

implement preventive and mitigating actions.

We currently estimate that we will incur costs of $604,000 in 2010 to implement pipeline integrity management program testing along certain segments of our pipeline, as required by existing DOT regulations. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, which could be substantial.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are therefore subject to the possibility of increased costs or the inability to retain necessary land use.

We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for specified periods of time. Many of these rights-of-way are perpetual in duration; others have terms ranging from five to ten years. Many are subject to rights of reversion in the case of non-utilization for periods

 

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ranging from one to three years. In addition, some of our processing facilities are located on leased premises. Our loss of these rights, through our inability to renew right-of-way contracts or leases or otherwise, could have a material adverse effect on our business, results of operations and financial condition.

In addition, 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 to capitalize on other attractive expansion opportunities. If the cost of obtaining new rights-of-way increases, then our cash flows and growth opportunities could be adversely affected.

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 hazardous substances into the environment.

Our operations are subject to stringent and complex federal, state and local environmental laws and regulations governing, among other things, air emissions, wastewater discharges, the use, management and disposal of hazardous and nonhazardous materials and wastes, and the cleanup of contamination. Noncompliance with such laws and regulations, or incidents resulting in environmental releases, could cause us to incur substantial costs, penalties, fines and other criminal sanctions, third party claims for personal injury or property damage, investments to retrofit or upgrade our facilities and programs, or curtailment of operations. Certain environmental statutes, including CERCLA and comparable state laws, impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to the necessity of handling natural gas and NGLs, air emissions related to our operations, and historical industry operations and waste disposal practices. For example, an accidental release from one of our pipelines or processing facilities could subject us to substantial liabilities arising from environmental cleanup and restoration costs, 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, the possibility exists 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 these costs from insurance. We cannot be certain that identification of presently unidentified conditions, more vigorous enforcement by regulatory agencies, enactment of more stringent laws and regulations, or other unanticipated events will not arise in the future and give rise to material environmental liabilities that could have a material adverse effect on our business, financial condition or results of operations.

Our operations may incur substantial liabilities to comply with climate change legislation and regulatory initiatives.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climate changes. In response to such studies, President Obama has expressed support for and Congress is considering a variety of legislation to reduce emissions of greenhouse gases Two of the bills, H.R. 2454 and S. 1733, employ a market-based cap-and-trade program, among other provisions, to reduce over time the emissions of greenhouse gases. The US House of Representatives approved H.R. 2454 on June 25, 2009. The Senate Environment and Public Works Committee adopted S. 1733 on November 5, 2009, but the bill has not yet been presented to the Senate for a vote. A cap-and-trade program could impose on us costs associated with the purchase of allowances or credits or costs associated with additional controls to manage emissions from our existing sources. An alternative bill, the Carbon Limits and Energy for America’s Renewal Act (“CLEAR”), was introduced in the Senate on December 9, 2009, and proposes to regulate the amount of fossil fuel carbon (defined to include natural gas) that producers and importers can introduce into domestic commerce. If enacted, CLEAR would require an entity in the business of producing fossil carbon to purchase the right to sell or otherwise place fossil carbon into commerce in the United States and also would reduce over time the total

 

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amount of fossil carbon that could be sold into domestic commerce. 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 greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas 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, such as refineries or gas processing plants, to acquire and, on an annual basis, surrender emission allowances. Depending on the particular program, we could be required to purchase and surrender allowances, either for greenhouse gas emissions resulting from our operations ( e.g. , compressor stations) or from the combustion of fuels ( e.g. , natural gas) we process.

In response to the United States Supreme Court’s holding in the 2007 decision, Massachusetts, et al. v. EPA (that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act), in December 2009, EPA issued its Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (“Endangerment Finding”), which found that greenhouse gas emissions endanger the public health and welfare and that the combined emissions of greenhouse gases from new motor vehicles contribute to global climate change. The Endangerment Finding does not itself impose any requirements on industry or other entities. It does, however, pave the way for EPA to finalize proposed greenhouse gas emission standards for motor vehicle sources which, in turn, could trigger stationary source controls under the Clean Air Act. Several parties have requested review of the Endangerment Finding with the U.S. Court of Appeals for the D.C. Circuit, but we cannot predict the outcome of the court’s review. In contemplation of the regulation of greenhouse gases emissions from stationary sources, in September 2009 EPA proposed new “applicability thresholds” for greenhouse gas emissions under the Clean Air Act’s Prevention of Significant Deterioration and Title V Operating Permit programs (“Tailoring Rule”). If promulgated as proposed, the Tailoring Rule would impose additional permitting requirements and the installation of “best available control technology” on new or modified stationary sources that emit more than 25,000 tons of carbon dioxide equivalent emissions annually. These proposed rules could go into effect during 2010. Any regulation of greenhouse gas emissions from stationary sources could apply to our processing, treating compression and pipeline facilities.

In addition, on January 19, 2010, EPA published a proposed rule that would reduce the NAAQS for ozone set in 2008 from 0.075 parts per million (“ppm”) to within the range of 0.060 to 0.070 ppm. Areas within states that we operate may not comply with the proposed NAAQS for ozone and, for those areas of nonattainment, states may adopt plans, known as State Implementation Plans, which could require new and modified sources of emissions to demonstrate compliance with allowable limits and may impose additional controls on our existing sources of ozone emissions.

It is not possible at this time to predict how legislation or new regulations that may be adopted to address greenhouse gas emissions would impact our business, but any such future laws and regulations could result in a potential decline in the production of natural gas, increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business or demand for the natural gas we gather and process.

We may not have the ability to raise funds necessary to finance any change of control offer required under our senior notes and our preferred units.

If a change of control (as defined in the indentures governing the senior notes) occurs, we will be required to offer to purchase our outstanding senior notes at 101 percent of their principal amount plus accrued and unpaid interest. If a purchase offer obligation arises under these indentures, a change of control could also have occurred under our credit facility, which could result in the acceleration of the indebtedness outstanding thereunder. Any of our future debt agreements may contain similar restrictions and provisions. If a purchase offer were required under the indentures for our debt (or under our credit facility), we may not have sufficient funds to pay the purchase price of all debt that we are required to purchase or repay.

 

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Our ability to manage and grow our business effectively may be adversely affected if our General Partner loses key management or operational personnel.

We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition, and on our ability to compete effectively in the marketplace. Additionally, the General Partner’s employees operate our business. Our General Partner’s ability to hire, train, and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions remain positive.

When general industry conditions are good, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow and perhaps even to continue our current level of service to our current customers will be adversely impacted if our General Partner is unable to successfully hire, train and retain these important personnel.

Terrorist attacks, the threat of terrorist attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the energy transportation industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas and NGLs and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

RISKS RELATED TO OUR STRUCTURE

GE EFS controls our General Partner, which has sole responsibility for conducting our business and managing our operations.

Although our General Partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of our General Partner have a fiduciary duty to manage our General Partner in a manner beneficial to its owner, GE EFS. Conflicts of interest may arise between GE EFS, including our General Partner, on the one hand, and us, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following situations:

 

 

 

neither our partnership agreement nor any other agreement requires GE EFS or affiliates of GECC to pursue a business strategy that favors us;

 

 

 

our General Partner is allowed to take into account the interests of parties other than us, such as GE EFS, in resolving conflicts of interest;

 

 

 

our General Partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and repayments of debt, issuance of additional partnership securities, and cash reserves, each of which can affect the amount of cash available for distribution;

 

 

 

our General Partner determines which costs incurred are reimbursable by us;

 

 

 

our partnership agreement does not restrict our General Partner from causing us to pay for any services rendered to us or entering into additional contractual arrangements with any of its affiliates on our behalf;

 

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our General Partner intends to limit its liability regarding our contractual and other obligations; and

 

 

 

our General Partner controls the enforcement of obligations owed to us by our General Partner.

GE EFS and other affiliates of GECC may compete directly with us.

GE EFS and other affiliates of GECC are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. GE EFS and its affiliates currently own various midstream assets and conduct midstream businesses that may potentially compete with us. In addition, GE EFS and its affiliates may acquire, construct or dispose of any additional midstream or other assets in the future, without any obligation to offer us the opportunity to purchase or construct or dispose of those assets.

Our reimbursement of our general partner’s expenses will reduce our cash available for distribution to common unitholders.

Prior to making any distribution on the common units, we will reimburse our General Partner and its affiliates for all expenses they incur on our behalf. These expenses will include all costs incurred by our General Partner and its affiliates in managing and operating us, including costs for rendering corporate staff and support services to us. The reimbursement of expenses incurred by our General Partner and its affiliates could adversely affect our ability to pay cash distributions to our unitholders.

Our partnership agreement limits our General Partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our General Partner might otherwise be held by state fiduciary duty law. For example, our partnership agreement:

 

 

 

permits our General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as our General Partner. This entitles our General Partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns, its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership;

 

 

 

provides that our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

 

 

 

provides generally that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our General Partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us, as determined by our General Partner in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” our General Partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

 

 

 

provides that our General Partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

Any unitholder is bound by the provisions in the partnership agreement, including the provisions discussed above.

 

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Unitholders have limited voting rights and are not entitled to elect our General Partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our General Partner or its Board of Directors and have no right to elect our General Partner or its Board of Directors on an annual or other continuing basis. The Board of Directors of our General Partner is chosen by the members of our General Partner. Furthermore, if the unitholders are dissatisfied with the performance of our General Partner, they will have little ability to remove our General Partner. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if unitholders are dissatisfied, they cannot remove our General Partner without its consent.

Our unitholders may be unable to remove the General Partner without its consent because the General Partner and its affiliates own a substantial number of common units. A vote of the holders of at least 66 2/3 percent of all outstanding units voting together as a single class is required to remove the General Partner. As of February 23, 2010 our General Partner owned 26.5 percent of the total of our common units.

Our partnership agreement restricts the voting rights of those unitholders owning 20 percent or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our General Partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of our General Partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of our management.

Control of our General Partner may be transferred to a third party without unitholder consent.

Our General Partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the partners of our general partner from transferring their ownership in our General Partner to a third party. The new partners of our General Partner would then be in a position to replace the Board of Directors and officers of our General Partner with their own choices and to control the decisions taken by the Board of Directors and officers.

We may issue an unlimited number of additional units without your approval, which would dilute your existing ownership interest.

Our General Partner, without the approval of our unitholders, may cause us to issue an unlimited number of additional common units or other equity securities. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

 

 

 

our unitholders’ proportionate ownership interest in us will decrease;

 

 

 

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

 

 

 

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

 

 

 

the market price of the common units may decline.

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

If at any time our General Partner and its affiliates own more than 80 percent of the common units, our General Partner will have the right, but not the obligation (which it may assign to any of its affiliates or to us) to

 

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acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of February 23, 2010 our General Partner owned 26.5 percent of the total of our common units.

Unitholders may not have limited liability if a court finds that unitholder actions constitute control of our business.

Under Delaware law, a unitholder could be held liable for our obligations to the same extent as a general partner if a court determined that the right of unitholders to remove our general partner or to take other action under our partnership agreement constituted participation in the “control” of our business.

Our General Partner generally has unlimited liability for our obligations, such as our debts and environmental liabilities, except for those contractual obligations that are expressly made without recourse to our General Partner. Our partnership agreement allows the general partner to incur obligations on our behalf that are expressly non-recourse to the general partner. The general partner has entered into such limited recourse obligations in most instances involving payment liability and intends to do so in the future.

In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

TAX RISKS

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 or local entities. If the IRS treats us as a corporation or we become subject to a material amount of entity-level taxation for state or local tax purposes, it would substantially reduce the amount of cash available for payment for distributions on our common units.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35 percent, and would likely pay state and local income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you 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 the unitholders, likely causing a substantial reduction in the value of the units.

Current law may change so as to cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. At the federal level, legislation has recently been considered that would have eliminated partnership tax treatment for certain publicly traded partnerships. Although such legislation would not have applied to us as proposed, it could be reintroduced in a manner that does apply to us. We are unable to predict whether any of these changes or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units. At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay a Texas margin tax. Imposition of such a tax on us by Texas, and, if applicable, by any other state, will reduce our cash available for distribution to you.

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

 

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A successful IRS contest of the federal income tax positions we take may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to you.

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 not agree with 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 and our general partner because the costs will reduce our cash available for distribution.

Unitholders may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, they will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the tax liability that results from that income.

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

If a unitholder sells his common units, he will recognize a gain or loss equal to the difference between the amount realized and his tax basis in those common units. Prior distributions to a unitholder in excess of the total net taxable income he was allocated for a common unit, which decreased his tax basis in that common unit, will, in effect, become taxable income to him if the common unit is sold at a price greater than his tax basis in that common unit, even if the price is less than his original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sells his common units, he may incur a tax liability in excess of the amount of cash he receives 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, such as individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-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 a unitholder is a tax-exempt entity or a non-U.S. person, he should consult his tax advisor before investing in our common units.

We will 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 because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax deductions available to a unitholder. It also could affect the timing of these tax deductions or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder’s tax returns.

 

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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. However, recently proposed Treasury Regulations provide a safe harbor for publicly traded partnerships pursuant to which a similar monthly convention is allowed. Existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations; however they are not binding on the IRS and are subject to change until final Treasury Regulations are issued. Accordingly, if the IRS were to challenge our method of allocating income, gain, loss and deduction between transferors and transferees, or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

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

In addition, for purposes of determining the amount of the unrealized gain or loss to be allocated to the capital accounts of our unitholders and our general partner, we will reduce the fair market value of our property (to the extent of any unrealized income or gain in our property that has not previously been reflected in the capital accounts) to reflect the incremental share of such fair market value that would be attributable to the holders of our outstanding convertible redeemable preferred units if all of such convertible redeemable preferred units were converted into common units as of such date. Consequently, a holder of common units may be allocated less unrealized gain in connection with an adjustment of the capital accounts than such holder would have been allocated if there were no outstanding convertible redeemable preferred units. Following the conversion of our convertible redeemable preferred units into common units, items of gross income and gain (or

 

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gross loss and deduction) will be specially allocated to the holders of such common units to reflect differences between the capital accounts maintained with respect to such convertible redeemable preferred units and the capital accounts maintained with respect to common units. This method of maintaining capital accounts and allocating income, gain, loss and deduction with respect to the convertible redeemable preferred units is intended to comply with proposed Treasury Regulations. However, these proposed Treasury Regulations are not legally binding and are subject to change until final Treasury Regulations are issued. Accordingly, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50 percent threshold has been reached, multiple sales of the same unit will be counted only once. Although a termination likely will cause our unitholders to realize an increased amount of taxable income as a percentage of the cash distributed to them, we anticipate that the ratio of taxable income to distributions for future years will return to levels commensurate with our prior tax periods. However, any future termination of our partnership could have similar consequences. Additionally, in the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. The position that there was a partnership termination does not affect our classification as a partnership for federal income tax purposes; however, we are treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to prevail that a termination occurred.

You may be subject to state and local taxes and tax return filing requirements.

In addition to federal income taxes, you 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 do business or own property, even if you do not live in any of those jurisdictions. You 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, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in Texas, Oklahoma, Kansas, Louisiana, West Virginia, Arkansas, Colorado and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax as well as an income tax on corporations and other entities. Texas imposes a margin tax on corporations and limited liability companies. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all United States federal, foreign, state and local tax returns required as a result of being a unitholder.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Substantially all of our pipelines, which are located in Texas, Louisiana, Oklahoma, and Kansas, are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the

 

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right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, properties on which our pipelines were built were purchased in fee. These pipelines are used in our gathering and processing segment and in our corporate and others segment. In 2009, we contributed the pipelines in our transportation segment to HPC.

We believe that we have satisfactory title to all our assets. Record title to some of our assets may continue to be held by prior owners until we have made the appropriate filings in the jurisdictions in which such assets are located. Obligations under our credit facility are secured by substantially all of our assets and are guaranteed by the Partnership. Title to our assets may also be subject to other encumbrances. We believe that none of such encumbrances should materially detract from the value of our properties or our interest in those properties or should materially interfere with our use of them in the operation of our business.

Our executive offices occupy two entire floors in an office building at 2001 Bryan Street, Suite 3700, Dallas, Texas, 75201, under a lease that expires on October 31, 2019. We also maintain regional offices located on leased premises in Shreveport, Louisiana, and Midland, Houston, Victoria and San Antonio, Texas and Damascus, Arkansas. 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.

For additional information regarding our properties, please read “Item 1—Business.”

Item 3. Legal Proceedings

We are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. Neither the Partnership nor any of its subsidiaries, including RGS, is, however, currently a party to any pending or, to our knowledge, threatened material legal or governmental proceedings, including proceedings under any of the various environmental protection statutes to which it is subject.

We maintain insurance policies with insurers in amounts and with coverages and deductibles that we, with the advice of our insurance advisors and brokers, believe are reasonable and prudent. We cannot, however, assure you that this insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage or that these levels of insurance will be available in the future at economical prices.

Item 4. Reserved

 

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Part II

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

Market Price of and Distributions on the Common Units and Related Unitholder Matters

Our common units were first offered and sold to the public on February 3, 2006. Our common units are listed on the NASDAQ Global Select Market under the symbol “RGNC.” As of February 23, 2010, the number of holders of record of common units was 170, with 66,899,318 units held in street name. Currently, our common units are listed on the Nasdaq Global Select Market. The following table sets forth, for the periods indicated, the high and low quarterly sales prices per common unit, as reported on the NASDAQ Global Select Market, and the cash distributions declared per common unit.

 

     Price Ranges    Cash
Distributions
 

Period

   High    Low    (per unit)  

2010

        

January 1, 2010 through February 23, 2010

   23.50    19.71    (1 ) 

2009

        

First Quarter

   12.89    8.08    0.4450   

Second Quarter

   14.68    11.00    0.4450   

Third Quarter(2)

   19.65    14.07    0.4450   

Fourth Quarter(2)

   21.00    18.56    0.4450   

2008

        

First Quarter(3)(4)

   34.84    25.78    0.4000   

Second Quarter(3)

   28.73    23.93    0.4200   

Third Quarter(3)

   26.88    15.75    0.4450   

Fourth Quarter(3)

   19.00    4.92    0.4450   

 

(1)

The cash distribution for the first quarter of 2010 will be determined in April 2010.

(2)

Excludes the Series A Redeemable Cumulative Convertible Preferred Units (“Series A Preferred Units”) which will receive fixed quarterly cash distributions of $0.445 beginning with the quarter ending March 31, 2010.

(3)

Excludes the Class D common units which were not entitled to any distributions until they were converted into common units. The Class D common units converted to common units on February 9, 2009.

(4)

Excludes the Class E common units which were not entitled to any distributions until they were converted into common units. The Class E common units converted to common units on May 5, 2008.

Cash Distribution Policy

We distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below. If we do not have sufficient cash to pay our distributions as well as satisfy our other operational and financial obligations, our General Partner has the ability to reduce or eliminate the distribution paid on our common units so that we may satisfy such obligations, including payments on our debt instruments.

Available cash generally means, for any quarter ending prior to liquidation of the Partnership, all cash on hand at the end of that quarter less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

 

 

 

provide for the proper conduct of our business;

 

 

 

comply with applicable law or any partnership debt instrument or other agreement; or

 

 

 

provide funds for distributions to unitholders and the General Partner in respect of any one or more of the next four quarters.

 

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In addition to distributions on its two percent General Partner interest, our General Partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in the following table.

 

    

Quarterly Distribution Per Unit
Target Amount

   Marginal Percentage
Interest in Distributions
        Unitholders    General
Partner
   Incentive
Distribution
Rights

Minimum Quarterly Distribution

  

$0.35

   98    2    —  

First Target Distribution

  

up to $0.4025

   98    2    —  

Second Target Distribution

  

above $0.4025 up to $0.4375

   85    2    13

Third Target Distribution

  

above $0.4375 up to $0.5250

   75    2    23

Thereafter

  

above $0.5250

   50    2    48

Under the terms of the agreements governing our debt, we are prohibited from declaring or paying any distribution to unitholders if a default or event of default (as defined in such agreements) exists. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for further discussion regarding the restrictions on distributions.

Recent Sales of Unregistered Securities

None.

 

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Item 6. Selected Financial Data

The historical financial information presented below for the Partnership was derived from our audited consolidated financial statements as of December 31, 2009, 2008, 2007, 2006 and 2005. See “Item 7—Management’s Discussions and Analysis of Financial Condition and Results of Operations—History of the Partnership and its Predecessor” for a discussion of why our results may not be comparable, either from period to period or going forward.

 

     Year Ended
December 31,
2009
    Year Ended
December 31,
2008
    Year Ended
December 31,
2007
    Year Ended
December 31,
2006
    Year Ended
December 31,
2005
 
     (in thousands except per unit data)  

Statement of Operations Data:

          

Total revenue

   $ 1,089,497      $ 1,863,804      $ 1,190,238      $ 896,865      $ 709,401   

Total operating expense

     864,861        1,699,831        1,130,874        857,005        695,366   
                                        

Operating income

     224,636        163,973        59,364        39,860        14,035   

Other income and deductions

          

Income from unconsolidated subsidiary

     7,886        —          —          —          —     

Interest expense, net

     (77,996     (63,243     (52,016     (37,182     (17,880

Loss on debt refinancing

     —          —          (21,200     (10,761     (8,480

Other income and deductions, net

     (15,132     332        1,252        839        733   
                                        

Net income (loss) from continuing operations

     139,394        101,062        (12,600     (7,244     (11,592

Discontinued operations

     —          —          —          —          732   

Income tax (benefit) expense

     (1,095     (266     931        —          —     
                                        

Net income (loss)

     140,489        101,328        (13,531     (7,244     (10,860

Net income attributable to noncontrolling interest

     91        312        305        —          —     
                                        

Net income (loss) attributable to Regency Energy Partners LP

   $ 140,398      $ 101,016      $ (13,836   $ (7,244   $ (10,860
                                        

Less:

          

Net income through January 31, 2006

     —          —          —          1,564     
                                  

Net income (loss) for partners

   $ 140,398      $ 101,016      $ (13,836   $ (8,808  
                                  

Amounts attributable to Series A convertible redeemable preferred units

     3,995        —          —          —       

General partner's interest, including IDR

     5,252        4,303        (366     (164  

Amount allocated to non-vested common units

     965        869        (103     (110  

Beneficial conversion feature for Class C common units

     —          —          1,385        3,587     

Beneficial conversion feature for Class D common units

     820        7,199        —          —       

Amount allocated to Class B common units

     —          —          —          (886  

Amount allocated to Class E common units

     —          —          5,792        —       
                                  

Limited partner interest

   $ 129,366      $ 88,645      $ (20,544   $ (11,235  
                                  

Basic net income (loss) per common and subordinated unit

   $ 1.61      $ 1.34      $ (0.40   $ (0.29  

Diluted net income (loss) per common and subordinated unit

     1.60        1.28        (0.40     (0.29  

Cash distributions declared per common and subordinated unit

     1.78        1.71        1.52        0.9417     

Basic and diluted net loss per Class B common unit

     —          —          —          (0.17  

Cash distributions declared per Class B common unit

     —          —          —          —       

Income per Class C common unit due to beneficial conversion feature

     —          —          0.48        1.26     

Cash distributions declared per Class C common unit

     —          —          —          —       

Income per Class D common unit due to beneficial conversion feature

     0.11        0.99        —          —       

Cash distributions declared per Class D common unit

     —          —          —          —       

Basic and diluted net income per Class E common units

     —          —          1.23        —       

Cash distributions per Class E common unit

     —          —          2.06        —       

 

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     Year Ended
December 31,
2009
    Year Ended
December 31,
2008
    Year Ended
December 31,
2007
    Year Ended
December 31,
2006
    Year Ended
December 31,
2005
 
     (in thousands)  

Balance Sheet Data (at period end):

          

Property, plant and equipment, net

   $ 1,456,435      $ 1,703,554      $ 913,109      $ 734,034      $ 609,157   

Total assets

     2,533,414        2,458,639        1,278,410        1,013,085        806,740   

Long-term debt (long-term portion only)

     1,014,299        1,126,229        481,500        664,700        428,250   

Series A convertible redeemable preferred units

     51,711        —          —          —          —     

Partners' capital and noncontrolling interest

     1,243,010        1,099,413        568,186        212,657        230,962   

Cash Flow Data:

          

Net cash flows provided by (used in):

          

Operating activities

   $ 143,960      $ 181,298      $ 79,529      $ 44,156      $ 37,340   

Investing activities

     (156,165     (948,629     (157,933     (223,650     (279,963

Financing activities

     21,433        734,959        99,443        184,947        242,949   

Other Financial Data:

          

Adjusted total segment margin(1)

   $ 379,411      $ 440,763      $ 228,652      $ 153,919      $ 88,022   

Adjusted EBITDA(1)

     205,160        254,473        142,234        92,811        51,230   

Maintenance capital expenditures

     20,170        18,247        8,764        16,433        9,158   

 

(1)

See “—Non-GAAP Financial Measures” for a reconciliation to its most directly comparable GAAP measure.

Non-GAAP Financial Measures

We include the following non-GAAP financial measures: EBITDA, adjusted EBITDA, total segment margin, and adjusted total segment margin. We provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures as calculated and presented in accordance with GAAP.

We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus non-cash loss (gain) from derivatives, (gain) loss on asset sales, net, loss on debt refinancing, other (income) expense, net, and the Partnership’s interest in adjusted EBITDA from unconsolidated subsidiaries less income from unconsolidated subsidiary. Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

 

 

 

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

 

 

 

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

 

 

 

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

 

 

 

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

Adjusted EBITDA is one of the critical inputs to the financial covenants within our credit agreement. The rates we pay for borrowings against this facility are determined by the ratio of our debt to adjusted EBITDA and by the ratio of our adjusted EBITDA to our interest expense. The calculation of these ratios allows for further pro forma adjustments to adjusted EBITDA for recent acquisitions, dispositions, and significant expansion projects. Based on the results of these ratios at the end of each reporting period, the credit spread on LIBOR borrowings will range from 3.25 percent to 2.5 percent. Our current credit spread is 3 percent. An event of default would occur if our debt to adjusted EBITDA was greater than 5.25, or if our adjusted EBITDA was less than 2.75 times interest expense. The credit agreement and associated amendments are filed as an exhibit to this Form 10-K.

EBITDA and adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance

 

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presented in accordance with GAAP. Our EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate adjusted EBITDA in the same manner.

EBITDA and adjusted EBITDA do not include interest expense, income taxes or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Corporate and Others segment margin as our revenue generated from operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

Prior to our contribution of RIGS to HPC, we calculated our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchased and sold gas for our account, gas sales revenue minus the cost of natural gas that we purchased and transported. After our contribution of RIGS to HPC, we do not record segment margin for the Transportation segment because we record our ownership percentage of the net income in HPC as income from an unconsolidated subsidiary.

We calculate our Contract Compression segment margin as revenue generated from our contract compression operations minus the direct costs, primarily compressor unit repairs, associated with that revenue.

We calculate total segment margin as the total of segment margin of our four segments, less the intersegment elimination. We define adjusted total segment margin as total segment margin adjusted for non-cash (gains) losses from derivatives.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the results of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes. Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin or adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts. As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these amounts in the same manner.

 

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     Year Ended
December 31, 2009
    Year Ended
December 31, 2008
    Year Ended
December 31, 2007
    Year Ended
December 31, 2006
    Year Ended
December 31, 2005
 
     (in thousands)  

Reconciliation of "Adjusted EBITDA" to net cash flows provided by operating activities and to net income (loss)

          

Net cash flows provided by operating activities

   $ 143,960      $ 181,298      $ 79,529      $ 44,156      $ 37,340   

Add (deduct):

          

Depreciation and amortization, including debt issuance cost amortization

     (116,307     (105,324     (57,069     (39,287     (24,286

Write-off of debt issuance costs

     —          —          (5,078     (10,761     (8,480

Non-cash income from unconsolidated subsidiary

     —          —          43        532        312   

Derivative valuation change

     (5,163     14,700        (14,667     2,262        (11,191

(Loss) gain on assets sales, net

     133,284        (472     (1,522     —          1,254   

Unit based compensation expenses

     (6,008     (4,306     (15,534     (2,906     —     

Gain on insurance settlement

     —          3,282        —          —          —     

Trade accounts receivable, accrued revenues and related party receivables

     (10,727     (18,648     28,789        5,506        43,012   

Other current assets

     (10,471     6,615        1,394        (104     2,644   

Trade accounts payable, accrued cost of gas and liquids, and related party payables

     3,762        40,772        (30,089     1,359        (52,651

Other current liabilities

     6,726        (12,749     149        (3,640     (2,075

Proceeds from early termination of interest rate swap

     —          —          —          (4,940     —     

Amount of swap termination proceeds reclassified into earnings

     —          —          1,078        3,862        —     

Other assets and liabilities

     1,433        (3,840     (554     (3,283     3,261   
                                        

Net income (loss)

     140,489        101,328        (13,531     (7,244     (10,860
                                        

Add (deduct):

          

Interest expense, net

     77,996        63,243        52,016        37,182        17,880   

Depreciation and amortization

     109,893        102,566        55,074        39,654        23,171   

Income tax (benefit) expense

     (1,095     (266     931        —          —     
                                        

EBITDA

     327,283        266,871        94,490        69,592        30,191   
                                        

Add (deduct):

          

Non-cash (gain) loss from derivatives

     5,163        (14,708     11,500        (6,158     9,530   

(Gain) loss on assets sales, net

     (133,284     472        1,522        —          —     

Income from unconsolidated subsidiary

     (7,886     —          —          —          —     

Partnership’s ownership interest in HPC’s adjusted EBITDA

     11,398        —          —          —          —     

Loss on debt refinancing

     —          —          21,200        10,761        8,480   

Other expense, net

     2,486        1,838        13,522        18,616        3,029   
                                        

Adjusted EBITDA

   $ 205,160      $ 254,473      $ 142,234      $ 92,811      $ 51,230   
                                        

Reconciliation of "Adjusted total segment margin" to net income (loss)

          

Net income (loss)

   $ 140,489      $ 101,328      $ (13,531   $ (7,244   $ (10,860

Add (deduct):

          

Operation and maintenance

     130,826        131,629        58,000        39,496        24,291   

General and administrative

     57,863        51,323        39,713        22,826        15,039   

Loss (gain) on assets sales, net

     (133,284     472        1,522        —          —     

Management services termination fee

     —          3,888        —          12,542        —     

Transaction expenses

     —          1,620        420        2,041        —     

Depreciation and amortization

     109,893        102,566        55,074        39,654        23,171   

Income from unconsolidated subsidiary

     (7,886     —          —          —          —     

Interest expense, net

     77,996        63,243        52,016        37,182        17,880   

Loss on debt refinancing

     —          —          21,200        10,761        8,480   

Other income and deductions, net

     15,132        (332     (1,252     (839     (733

Discontinued operations

     —          —          —          —          (732

Income tax (benefit) expense

     (1,095     (266     931        —          —     
                                        

Total segment margin

     389,934        455,471        214,093        156,419        76,536   
                                        

Add (deduct):

          

Non-cash (gain) loss from derivatives

     (10,523     (14,708     11,500        (6,158     9,530   

Non-cash put option expiration

     —          —          3,059        3,658        1,956   
                                        

Adjusted total segment margin

   $ 379,411      $ 440,763      $ 228,652      $ 153,919      $ 88,022   
                                        

 

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

The following discussion analyzes our financial condition and results of operations. You should read the following discussion of our financial condition and results of operations in conjunction with our historical consolidated financial statements and notes included elsewhere in this document.

OVERVIEW. We are a growth-oriented publicly-traded Delaware limited partnership, formed in 2005, engaged in the gathering, processing, contract compression and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma.

OUR OPERATIONS. We divide our operations into four business segments:

 

 

 

Gathering and Processing: We provide “wellhead-to-market” services to producers of natural gas, which include transporting raw natural gas from the wellhead through gathering systems, processing raw natural gas to separate NGLs and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems;

 

 

 

Transportation: We own a 43 percent interest in HPC which, through RIGS, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system;

 

 

 

Contract Compression: We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations; and

 

 

 

Corporate and Others: We own and operate an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. This pipeline has a FERC certificated capacity of 150 MMcf/d.

Gathering and Processing segment. Results of operations from our Gathering and Processing segment are determined primarily by the volumes of natural gas that we gather and process, our current contract portfolio, and natural gas and NGL prices. We measure the performance of this segment primarily by the adjusted segment margin it generates. We gather and process natural gas pursuant to a variety of arrangements generally categorized as “fee-based” arrangements, “percent-of-proceeds” arrangements and “keep-whole” arrangements. Under fee-based arrangements, we earn fixed cash fees for the services that we render. Under the latter two types of arrangements, we generally purchase raw natural gas and sell processed natural gas and NGLs. We regard the adjusted segment margin generated by our sales of natural gas and NGLs under percent-of-proceeds and keep-whole arrangements as comparable to the revenues generated by fixed fee arrangements to the extent that they are hedged. The following is a summary of our most common contractual arrangements:

 

 

 

Fee-Based Arrangements. Under these arrangements, we are generally paid a fixed cash fee for performing the gathering and processing service. This fee is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. A sustained decline in commodity prices, however, could result in a decline in volumes and, thus, a decrease in our fee revenues. These arrangements provide stable cash flows, but minimal, if any, upside in higher commodity price environments.

 

 

 

Percent-of-Proceeds Arrangements. Under these arrangements, we generally gather raw natural gas from producers at the wellhead, transport it through our gathering system, process it and sell the processed gas and NGLs at prices based on published index prices. In this type of arrangement, we retain the sales proceeds less amounts remitted to producers and the retained sales proceeds constitute our margin. These arrangements provide upside in high commodity price environments, but result in lower margins in low commodity price environments. Under these arrangements, our margins typically cannot be negative. We regard the margin from this type of arrangement as an important analytical measure of these arrangements. The price paid to producers is based on an agreed percentage of one of

 

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the following: (1) the actual sale proceeds; (2) the proceeds based on an index price; or (3) the proceeds from the sale of processed gas or NGLs or both. Under this type of arrangement, our margin correlates directly with the prices of natural gas and NGLs (although there is often a fee-based component to these contracts in addition to the commodity sensitive component).

 

 

 

Keep-Whole Arrangements. Under these arrangements, we process raw natural gas to extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas received from the producer in processed gas or its cash equivalent. We are generally entitled to retain the processed NGLs and to sell them for our account. Accordingly, our margin is a function of the difference between the value of the NGLs produced and the cost of the processed gas used to replace the thermal equivalent value of those NGLs. The profitability of these arrangements is subject not only to the commodity price risk of natural gas and NGLs, but also to the price of natural gas relative to NGL prices. These arrangements can provide large profit margins in favorable commodity price environments, but also can be subject to losses if the cost of natural gas exceeds the value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions that reduce our commodity price exposure, including (1) embedded discounts to the applicable natural gas index price under which we may reimburse the producer an amount in cash for the thermal equivalent volume of raw natural gas acquired from the producer, (2) fixed cash fees for ancillary services, such as gathering, treating, and compression, or (3) the ability to bypass processing in unfavorable price environments.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our adjusted segment margin is based in part on natural gas and NGL prices. We seek to minimize our exposure to fluctuations in commodity prices in several ways, including managing our contract portfolio. In managing our contract portfolio, we classify our gathering and processing contracts according to the nature of commodity risk implicit in the settlement structure of those contracts. For example, we seek to replace our longer term keep-whole arrangements as they expire or whenever the opportunity presents itself.

Another way we minimize our exposure to commodity price fluctuations is by executing swap contracts settled against ethane, propane, butane, natural gasoline, natural gas, and WTI market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

In addition, we perform a producer services function that is conducted by a separate subsidiary. We purchase natural gas from producers or gas marketers at receipt points on our systems, including HPC, and transport that gas to delivery points on HPC’s system at which we sell the natural gas at market price. We regard the segment margin with respect to those purchases and sales as the economic equivalent of a fee for our transportation service. These contracts are frequently settled in terms of an index price for both purchases and sales. In order to minimize commodity price risk, we attempt to match sales with purchases at the index price.

We sell natural gas on intrastate and interstate pipelines to gas marketing companies, independent power producers, and utilities. We typically sell natural gas under pricing terms related to a market index. To the extent possible, we match the pricing and timing of our supply portfolio to our sales portfolio in order to lock in our margin and reduce our overall commodity price exposure. To the extent our natural gas position is not balanced, we will be exposed to the commodity price risk associated with the price of natural gas. Please refer to “Item 7A—Quantitative and Qualitative Disclosure about Market Risk” for further details.

Transportation segment: We own a 43 percent interest in HPC which, through RIG, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system. Results of HPC’s operations are determined primarily by the volumes of natural gas transported on its intrastate pipeline system and the level of fees charged to the customers or the margins received from purchases and sales of natural gas. HPC generates revenue and segment margins principally under fee-based transportation contracts or through the purchases of natural gas at one of the inlets to the pipeline and the sales of natural gas at an outlet.

 

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The margin HPC earns is directly related to the volume of natural gas that flows through its system and is not directly dependent on commodity prices. If a sustained decline in commodity prices should result in a decline in volumes, HPC’s revenue from these arrangements would be reduced.

Generally, HPC, through RIGS, provides to shippers two types of fee-based transportation services:

 

 

 

Firm Transportation. When RIG agrees to provide firm transportation service, it becomes obligated to transport natural gas nominated by the shipper up to the maximum daily quantity specified in the contract. In exchange for that obligation on RIG’s part, the shipper pays a specified reservation charge, whether or not it utilizes the capacity. In most cases, the shipper also pays a commodity charge with respect to quantities actually transported by RIGS.

 

 

 

Interruptible Transportation. When RIG agrees to provide interruptible transportation service, it becomes obligated to transport natural gas nominated by the shipper only to the extent that it has available capacity. For this service, the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped.

HPC, through RIGS, provides transportation services under the terms of its contracts and under an operating statement that RIG has filed with FERC with respect to transportation authorized under section 311 of the NGPA.

Contract Compression segment. We provide turn-key natural gas compression services whereby we guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations. We operate more than 753,000 horsepower of compression for third-party producers in Texas, Louisiana, Arkansas and Pennsylvania. In addition, our contract compression segment operates approximately 149,000 horsepower of compression for our gathering and processing segment and also operates approximately 29,000 horsepower of compression owned by RIG.

HOW WE EVALUATE OUR OPERATIONS. Our management uses a variety of financial and operational measurements to analyze our performance. We view these measures as important tools for evaluating the success of our operations and review these measurements on a monthly basis for consistency and trend analysis. These measures include volumes, segment margin, total segment margin, adjusted segment margin, adjusted total segment margin, operating and maintenance expenses, EBITDA, and adjusted EBITDA on a segment and company-wide basis.

Volumes. We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. Our ability to maintain existing supplies of natural gas and obtain new supplies is affected by (i) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (ii) our ability to compete for volumes from successful new wells in other areas and (iii) our ability to obtain natural gas that has been released from other commitments. We routinely monitor producer activity in the areas served by our gathering and processing systems to pursue new supply opportunities.

Segment Margin and Total Segment Margin. We define segment margin, generally, as revenue minus cost of sales. We calculate our Gathering and Processing segment margin and Corporate and Others segment margin as our revenue generated from operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.

Prior to our contribution of RIGS to HPC, we calculated our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchased and sold gas for our account, gas sales revenue minus the cost of natural gas that we purchased and transported. After our contribution of RIGS to HPC, we do not record segment margin for the Transportation segment because we record our ownership percentage of the net income in HPC as income from an unconsolidated subsidiary.

 

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We calculate our Contract Compression segment margin as our revenue generated from our contract compression operations minus the direct costs, primarily compressor unit repairs, associated with that revenue.

We calculate total segment margin as the total of segment margin of our four segments, less the intersegment elimination.

Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin for our Gathering and Processing segment as gathering and processing segment margin adjusted for non-cash gains (losses) from derivatives. We define adjusted segment margin for our Transportation segment as Transportation segment margin adjusted for non-cash gains (losses) from derivatives. Adjusted segment margin is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product purchases and sales, a key component of our operations.

We define adjusted total segment margin as total segment margin adjusted for non-cash gains (losses) from derivatives. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, including intersegment eliminations.

Operation and Maintenance Expense. Operation and maintenance expense is a separate measure that we use to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operating and maintenance expense. These expenses are largely independent of the volumes through our systems but fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating segment margin because we separately evaluate commodity volume and price changes in segment margin.

EBITDA and Adjusted EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus non-cash loss (gain) from derivative activities, loss (gain) on asset sales, net, loss on debt refinancing, other (income) expense, net, and the Partnership’s interest in adjusted EBITDA from unconsolidated subsidiaries less income from unconsolidated subsidiary. These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:

 

 

 

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

 

 

 

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

 

 

 

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

 

 

 

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

Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly-traded partnership. See “Item 6—Selected Financial Data” for a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by (used in) operating activities and to net income (loss).

GENERAL TRENDS AND OUTLOOK. We expect our business to continue to be affected by the following key trends. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about or interpretations of available information prove incorrect, our actual results may vary materially from our expected results.

 

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Natural Gas Supply and Demand. At December 31, 2009, the number of working natural gas drilling rigs in the United States totaled 759 compared to 665 in mid July of 2009, a 14 percent increase. EIA expects a 3 percent decline in natural gas production in 2010 due to the natural decline in existing well production and the lagged effect of reduced drilling. EIA also expects production to increase by 1.3 percent in 2011. Demand for natural gas in 2010 is expected to remain unchanged. EIA expects that higher prices for natural gas in 2010 will decrease the consumption in the electric power section by 2.8 percent; this decline is expected to be offset by growth in the residential, commercial and industrial sectors. Natural gas consumption in 2011 is expected to increase by 0.4 percent, led by a 2.5 percent increase in consumption in the industrial sector. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

EIA forecasts demand for crude oil and NGLs to increase in 2010 and 2011. Total petroleum consumption is forecasted to increase by 1.1 percent in 2010 with all of the major components contributing to this increase.

Fluctuations in energy prices can affect production rates over time and levels of investment by third parties in exploration for and development of new natural gas reserves. We have no control over the level of natural gas exploration and development activity in the areas of our operations.

Outlook. Global financial markets and economic conditions have been, and continue to be, volatile. The cost of raising money from the credit market generally has increased. As we expect to continue to incur substantial capital expenditures and working capital needs, we may experience difficulty in accessing the capital markets.

Effect of Interest Rates and Inflation. Interest rates on existing and future credit facilities and future debt offerings could be significantly higher than current levels, causing our financing costs to increase accordingly. Although increased financing costs could limit our ability to raise funds in the capital markets, we expect to remain competitive with respect to acquisitions and capital projects since our competitors would face similar circumstances.

Inflation in the United States has been relatively low in recent years and did not have a material effect on our results of operations. It may in the future, however, increase the cost to acquire or replace property, plant and equipment and may increase the costs of labor and supplies. Our operating revenue and costs are influenced to a greater extent by price changes in natural gas and NGLs. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along a portion of increased costs to our customers in the form of higher fees.

HISTORY OF THE PARTNERSHIP

Initial Public Offering. Prior to the closing of our initial public offering on February 3, 2006, Regency Gas Services LLC was converted into a limited partnership named Regency Gas Services LP, and was contributed to us by Regency Acquisition LP, a limited partnership indirectly owned by the HM Capital Investors.

Enbridge Asset Acquisition. TexStar acquired two sulfur recovery plants, one NGL plant and 758 miles of pipelines in east and south Texas from subsidiaries of Enbridge for $108,282,000 inclusive of transaction expenses on December 7, 2005. The Enbridge acquisition was accounted for using the purchase method of accounting. The results of operations of the Enbridge assets are included in our statements of operations beginning December 1, 2005.

Acquisition of TexStar. On August 15, 2006, we acquired all the outstanding equity of TexStar for $348,909,000, which consisted of $62,074,000 in cash, the issuance of 5,173,189 Class B common units valued at $119,183,000 to an affiliate of HM Capital, and the assumption of $167,652,000 of TexStar’s outstanding bank debt. Because the TexStar acquisition was a transaction between commonly controlled entities, we accounted for the TexStar acquisition in a manner similar to a pooling of interests. As a result, our historical financial statements and the historical financial statements of TexStar have been combined to reflect the historical operations, financial position and cash flows for periods in which common control existed, December 1, 2004 forward.

 

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Pueblo Acquisition. On April 2, 2007, we acquired a 75 MMcf/d gas processing and treating facility, 33 miles of gathering pipelines and approximately 6,000 horsepower of compression. The purchase price for the Pueblo acquisition consisted of (1) the issuance of 751,597 common units, valued at $19,724,000 and (2) the payment of $34,855,000 in cash, exclusive of outstanding Pueblo liabilities of $9,822,000 and certain working capital amounts acquired of $108,000. The Pueblo acquisition was accounted for using the purchase method of accounting. The results of operations of the Pueblo assets are included in our statements of operations beginning April 1, 2007.

GE EFS acquisition of HM Capital’s Interest. On June 18, 2007, indirect subsidiaries of GECC acquired 91.3 percent of both the member interest in the General Partner and the outstanding limited partner interests in the General Partner from an affiliate of HM Capital Partners and acquired 17,763,809 of the outstanding subordinated units, exclusive of 1,222,717 subordinated units which were owned directly or indirectly by certain members of the Partnership’s management team. The Partnership was not required to record any adjustments to reflect the acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions.

Acquisition of FrontStreet. On January 7, 2008, we acquired all of the outstanding equity and minority interest (the “FrontStreet Acquisition”) of FrontStreet from ASC, an affiliate of GECC, and EnergyOne. The total purchase price consisted of (a) 4,701,034 Class E common units of the Partnership issued to ASC in exchange for its 95 percent interest and (b) $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract valued at $3,888,000. We financed the cash portion of the purchase price with borrowings under our revolving credit facility.

Because the acquisition of ASC’s 95 percent interest is a transaction between commonly controlled entities, the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method. Information included in these financial statements is presented as if the FrontStreet Acquisition had been combined throughout the periods presented in which common control existed, June 18, 2007 forward. Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which we applied the purchase method of accounting.

Acquisition of CDM. On January 15, 2008, we and an indirect wholly owned subsidiary consummated an agreement and plan of merger with CDM Resource Management, Ltd. The total purchase price consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations. The results of operations of CDM are included in our statements of operations beginning January 16, 2008.

Acquisition of Nexus. On March 25, 2008, we acquired Nexus by merger for $88,640,000 in cash, including customary closing adjustments. The results of operations of Nexus are included in our statements of operations beginning March 26, 2008.

Formation of HPC. On March 17, 2009, we completed a joint venture arrangement (HPC) among Regency HIG, EFS Haynesville, and the Alinda Investors. We contributed RIGS valued at $401,356,000 in exchange for a 38 percent interest in HPC. On September 2, 2009, we purchased an additional five percent interest from EFS Haynesville for $63,000,000, increasing the Partnership’s ownership percentage from 38 percent to 43 percent.

 

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RESULTS OF OPERATIONS

Year Ended December 31, 2009 vs. Year Ended December 31, 2008

 

     Year Ended December 31,              
     2009     2008     Change     Percent  
     (in thousands except percentages and
volume data)
       

Total revenues

   $ 1,089,497      $ 1,863,804      $ (774,307   42

Cost of sales

     699,563        1,408,333        (708,770   50   
                          

Total segment margin(1)

     389,934        455,471        (65,537   14   

Operation and maintenance

     130,826        131,629        (803   1   

General and administrative

     57,863        51,323        6,540      13   

(Gain) loss on asset sales, net

     (133,284     472        (133,756   28,338   

Management services termination fee

     —          3,888        (3,888   N/M   

Transaction expenses

     —          1,620        (1,620   N/M   

Depreciation and amortization

     109,893        102,566        7,327      7   
                          

Operating income

     224,636        163,973        60,663      37   

Income from unconsolidated subsidiary

     7,886        —          7,886      N/M   

Interest expense, net

     (77,996     (63,243     (14,753   23   

Other income and deductions, net

     (15,132     332        (15,464   4,658   
                          

Income before income taxes

     139,394        101,062        38,332      38   

Income tax benefit

     (1,095     (266     (829   312   
                          

Net income

     140,489        101,328        39,161      39   

Net income attributable to the noncontrolling interest

     (91     (312     221      71   
                          

Net income attributable to Regency Energy Partners LP

   $ 140,398      $ 101,016      $ 39,382      39
                          

Total segment margin(1)

   $ 389,934      $ 455,471      $ (65,537   14

Add (deduct):

        

Non-cash gain from derivatives

     (10,523     (14,708     4,185      28   
                          

Adjusted total segment margin

     379,411        440,763        (61,352   14   

Transportation segment margin

     11,714        66,888        (55,174   82   

Contract compression segment margin

     141,028        125,503        15,525      12   

Corporate and others segment margin

     11,284        3,248        8,036      247   

Inter-segment eliminations

     (4,604     (4,573     (31   1   
                          

Adjusted gathering and processing segment margin

   $ 219,989      $ 249,697      $ (29,708   12
                          

System inlet volumes (MMBtu/d)(2)

     1,538,750        1,522,431        16,319      1

 

(1)

For reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data.”

(2)

System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

N/M

Not meaningful.

 

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The table below contains key segment performance indicators related to our discussion of our results of operations.

 

     Year Ended December 31,             
         2009            2008        Change     Percent  
     (in thousands except percentages and
volume data)
       

Gathering and Processing Segment

          

Financial data:

          

Adjusted segment margin(1)

   $ 219,989    $ 249,697    $ (29,708   12

Operation and maintenance(2)

     88,520      82,689      5,831      7   

Operating data:

          

Throughput (MMBtu/d)(3)

     1,000,621      1,025,779      (25,158   2   

NGL gross production (Bbls/d)

     24,024      22,390      1,634      7   

Transportation Segment

          

Financial data:

          

Segment margin(1)

   $ 11,714    $ 66,888    $ (55,174   82

Operation and maintenance(2)

     2,112      3,540      (1,428   40   

Operating data:

          

Throughput (MMBtu/d)(3)

     169,143      770,939      (601,796   78   

Contract Compression

          

Financial data:

          

Segment margin(1)

   $ 141,028    $ 125,503    $ 15,525      12

Operation and maintenance(2)

     45,744      49,799      (4,055   8   

Operating data:

          

Revenue generating horsepower(4)

     753,328      778,667      (25,339   3

Average horsepower per revenue generating compression unit

     849      856      (7   1   

Corporate and Others

          

Financial data:

          

Segment margin(1)

   $ 11,284    $ 3,248    $ 8,036      247

Operation and maintenance(2)

     426      74      352      476   

 

(1)

Combined adjusted segment margin for our segments differs from consolidated total adjusted segment margin due to intersegment eliminations.

(2)

Combined operation and maintenance expense varies from consolidated operation and maintenance expense due to intersegment eliminations.

(3)

Combined throughput volumes for the gathering and processing and transportation segments vary from consolidated system inlet volumes due to intersegment eliminations.

(4)

Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

 

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The following tables set forth certain information regarding contract compression’s revenue generating horsepower as of December 31, 2009 and 2008.

 

    Year Ended December 31,
    2009   2008

Horsepower Range

  Revenue Generating
Horsepower
  Percentage of
Revenue
Generating
Horsepower
    Number of Units   Revenue Generating
Horsepower
  Percentage of
Revenue
Generating
Horsepower
    Number of Units

0-499

  65,397   9   361   59,288   7   351

500-999

  74,826   10   121   83,299   11   134

1,000+

  613,105   81   405   636,080   82   425
                           
  753,328   100   887   778,667   100   910
                           

Despite the decrease in the amount of drilling activity during 2009, we only experienced a three percent decrease in revenue generating horsepower due to successful renewals of our customer contracts.

Net Income Attributable to Regency Energy Partners LP. Net income attributable to Regency Energy Partners LP increased to $140,398,000 in the year ended December 31, 2009 from $101,016,000 in the year ended December 31, 2008. The increase is primarily due to the recording of a $133,451,000 gain associated with the contribution of RIG to HPC, $7,886,000 in income from HPC and the absence in 2009 of $3,888,000 of management service termination fees related to the acquisition of our FrontStreet assets in 2008. These increases were partially offset by:

 

 

 

a decrease in total segment margin of $65,537,000 due primarily to the contribution of RIG to HPC on March 17, 2009 as well as lower commodity prices;

 

 

 

a decrease in other income and deductions, net of $15,464,000 which primarily relates to the non-cash value change associated with the embedded derivative related to the Series A Preferred Units issued in September 2009;

 

 

 

an increase in interest expense of $14,753,000 related primarily to the issuance of $250,000,000 of senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate;

 

 

 

an increase in depreciation and amortization expense of $7,327,000 related primarily to organic growth projects completed in 2009; and

 

 

 

an increase in general and administrative expenses of $6,540,000 primarily due to an increase in employee-related expenses.

Adjusted Total Segment Margin. Adjusted total segment margin decreased to $379,411,000 in the year ended December 31, 2009 from $440,763,000 in the year ended December 31, 2008. This decrease was attributable to a decrease of $29,708,000 in the adjusted gathering and processing segment margin, and a decrease of $55,174,000 in transportation segment margin related to the contribution of RIG to HPC, which was offset by the addition of $15,525,000 in contract compression segment margin, and the addition of $8,036,000 in corporate and others segment margin.

Adjusted gathering and processing segment margin decreased to $219,989,000 for the year ended December 31, 2009 from $249,697,000 for the year ended December 31, 2008. The major components of this decrease were as follows:

 

 

 

$24,066,000 related to lower commodity prices compared to the 2008 price levels; and

 

 

 

$5,642,000 from various other sources primarily related to our producer services function.

 

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Transportation segment margin decreased to $11,714,000 for the year ended December 31, 2009 from $66,888,000 for the year ended December 31, 2008, which was primarily attributable to the contribution of RIG to HPC on March 17, 2009.

Contract compression segment margin increased to $141,028,000 in the year ended December 31, 2009 from $125,503,000 in 2008. The increase is attributable to higher revenue generating horsepower in the first half of 2009 compared to the same period in 2008. The contract compression segment margin is also enhanced by the exclusion of 15 days in 2008 due to the timing of our CDM acquisition.

Corporate and others segment margin increased to $11,284,000 in the year ended December 31, 2009 from $3,248,000 in 2008. The increase is attributable to the following:

 

 

 

$4,726,000 in reimbursement of management fees from HPC for general and administrative expenses;

 

 

 

$2,576,000 additional segment margin generated from increased volumes in 2009 for a regulated entity; and

 

 

 

$734,000 from various other sources primarily related to our interstate pipeline.

Operation and Maintenance. Operation and maintenance expense remained relatively consistent with the year ended December 31, 2008, declining $803,000 in 2009, a one percent decrease. The changes in operations and maintenance expense for the year are the result of the following factors:

 

 

 

$6,628,000 decrease related to the contribution of RIG to HPC;

 

 

 

$1,630,000 decrease in materials and parts costs as a result of cost control measures; and were offset by

 

 

 

$7,317,000 increase in compression operation and maintenance expense in the gathering and processing segment due to the increased focus on maintenance of our compression fleet; and

 

 

 

$138,000 increase in various other operation and maintenance expenses.

General and Administrative. General and administrative expense increased to $57,863,000 in the year ended December 31, 2009 from $51,323,000 in 2008, a 13 percent increase. This increase is primarily the result of the following factors:

 

 

 

$3,925,000 increase in employee-related expenses due to increased employer benefits payments and incentive compensation accruals; and

 

 

 

$1,301,000 increase in professional and consulting service fees.

(Gain) Loss on Sale of Asset, net. Gain on sale of asset, net in 2009 primarily consisted of $133,451,000 in gain attributable to the contribution of RIG to HPC.

Depreciation and Amortization. Depreciation and amortization expense increased to $109,893,000 in the year ended December 31, 2009 from $102,566,000 in the year ended December 31, 2008, a seven percent increase. The increase was primarily due to:

 

 

 

$18,977,000 increase related to various organic growth projects completed since December 31, 2008; offset by

 

 

 

$11,650,000 decrease in depreciation expense related to the contribution of RIG to HPC.

Interest Expense, Net. Interest expense, net increased to $77,996,000 in the year ended December 31, 2009 from $63,243,000 in 2008. This increase was primarily attributable to the issuance of $250,000,000 of 9.375 percent senior notes in May 2009.

 

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Other Income and Deductions, net. Other income and deductions, net increased $15,464,000 in 2009 compared to 2008 primarily due to the non-cash value change in the embedded derivatives related to the Series A Preferred Units issued in September 2009.

Year Ended December 31, 2008 vs. Year Ended December 31, 2007

The table below contains key company-wide performance indicators related to our discussion of the results of operations.

 

      Year Ended December 31,              
      2008     2007     Change     Percent  
     (in thousands except percentages and
volume data)
       

Total revenues

   $ 1,863,804      $ 1,190,238      $ 673,566      57

Cost of sales

     1,408,333        976,145        432,188      44   
                          

Total segment margin(1)

     455,471        214,093        241,378      113   

Operation and maintenance

     131,629        58,000        73,629      127   

General and administrative

     51,323        39,713        11,610      29   

Loss on asset sales, net

     472        1,522        (1,050   69   

Management services termination fee

     3,888        —          3,888      N/M   

Transaction expenses

     1,620        420        1,200      286   

Depreciation and amortization

     102,566        55,074        47,492      86   
                          

Operating income

     163,973        59,364        104,609      176   

Interest expense, net

     (63,243     (52,016     (11,227   22   

Loss on debt refinancing

     —          (21,200     21,200      N/M   

Other income and deductions, net

     332        1,252        (920   73   
                          

Income (loss) before income taxes

     101,062        (12,600     113,662      902   

Income tax (benefit) expense

     (266     931        (1,197   129   
                          

Net income (loss)

     101,328        (13,531     114,859      849   

Net income attributable to the noncontrolling interest

     (312     (305     (7   2   
                          

Net income (loss) attributable to Regency Energy Partners LP

   $ 101,016      $ (13,836   $ 114,852      830
                          

Total segment margin(1)

   $ 455,471      $ 214,093      $ 241,378      113

Add (deduct):

        

Non-cash (gain) loss from derivatives

     (14,708     11,500        (26,208   228   

Non-cash put option expiration

     —          3,059        (3,059   N/M   
                          

Adjusted total segment margin

     440,763        228,652        212,111      93   

Transportation segment margin

     66,888        52,548        14,340      27   

Non-cash gain from derivatives

     —          (390     390      N/M   
                          

Adjusted transportation segment margin

     66,888        52,158        14,730      28   

Contract compression segment margin

     125,503        —          125,503      N/M   

Corporate and other segment margin

     3,248        2,362        886      38   

Inter-segment elimination

     (4,573     —          (4,573   N/M   
                          

Adjusted gathering and processing segment margin

   $ 249,697      $ 174,132      $ 75,565      43
                          

System inlet volumes (MMBtu/d)(2)

     1,522,431        1,225,918        296,513      24

 

(1)

For reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 6. Selected Financial Data.”

(2)

System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

N/M

Not meaningful.

 

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The table below contains key segment performance indicators related to our discussion of our results of operations.

 

      Year Ended December 31,             
      2008    2007    Change     Percent  
     (in thousands except percentages and
volume data)
       

Gathering and Processing Segment

          

Financial data:

          

Adjusted segment margin(1)

   $ 249,697    $ 174,132    $ 75,565      43

Operation and maintenance(2)

     82,689      53,496      29,193      55   

Operating data:

          

Throughput (MMBtu/d)(3)

     1,025,779      772,930      252,849      33   

NGL gross production (Bbls/d)

     22,390      21,808      582      3   

Transportation Segment

          

Financial data:

          

Adjusted segment margin(1)

   $ 66,888    $ 52,158    $ 14,730      28

Operation and maintenance(2)

     3,540      4,407      (867   20   

Operating data:

          

Throughput (MMBtu/d)(3)

     770,939      751,761      19,178      3   

Contract Compression

          

Financial data:

          

Segment margin(1)

   $ 125,503      N/A      N/A      N/A   

Operation and maintenance(2)

     49,799      N/A      N/A      N/A   

Operating data:

          

Revenue generating horsepower(4)

     778,667      N/A      N/A      N/A   

Average horsepower per revenue generating compression unit

     856      N/A      N/A      N/A   

Corporate and Others

          

Financial data:

          

Segment margin(1)

   $ 3,248    $ 2,362    $ 886      38

Operation and maintenance(2)

     74      97      (23   24   

 

(1)

Combined adjusted segment margin for our segments differs from consolidated total adjusted segment margin due to inter-segment eliminations.

(2)

Combined operation and maintenance expense for our segments differs from consolidated operation and maintenance expense due to inter-segment eliminations.

(3)

Combined throughput volumes for the gathering and processing and transportation segment vary from consolidated system inlet volumes due to inter-segment eliminations.

(4)

Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

N/A

Not applicable as we acquired the contract compression segment in January 2008.

Net Income (Loss) Attributable to Regency Energy Partners LP. Net income attributable to Regency Energy Partners LP for the year ended December 31, 2008 increased $114,852,000, compared with the year ended December 31, 2007. The increase in net income attributable to the Partnership was primarily attributable to an increase in total segment margin of $241,378,000 and the absence in the current period of a $21,200,000 loss on debt refinancing related to the termination penalty associated with the redemption of 35 percent of our senior notes. The increase in total segment margin was primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth in the gathering and processing segment. We were required to use the as-if pooling method of accounting for our FrontStreet acquisition because it involved entities under

 

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common control. Common control began on June 18, 2007, therefore the discussion below includes activity from FrontStreet from June 18, 2007 forward even though the acquisition occurred in January 2008. Partially offsetting these increases in net income attributable to the Partnership were:

 

 

 

an increase in operation and maintenance expense of $73,629,000 primarily due to our contract compression and FrontStreet assets acquired in January 2008 and increases in organic growth-related maintenance and employee-related expenses mainly in the gathering and processing segment;

 

 

 

an increase in depreciation and amortization expense of $47,492,000 primarily due to the acquisition of our contract compression, FrontStreet, and Nexus assets and organic growth projects primarily in the gathering and processing segment;

 

 

 

A net increase in general and administrative expenses of $11,610,000 primarily due to our contract compression acquisition in January 2008 and increased employee-related expenses, which was reduced by the absence of an $11,928,000 expense associated with the vesting of all outstanding LTIP grants incurred in 2007 when GE EFS acquired our general partner;

 

 

 

an increase in interest expense of $11,227,000 primarily due to increased levels of borrowings; and

 

 

 

a payment of a management contract services termination fee of $3,888,000 in 2008 related to the acquisition of FrontStreet.

Adjusted Total Segment Margin. Adjusted total segment margin for the year ended December 31, 2008 increased by $212,111,000 compared with the year ended December 31, 2007. This increase was attributable to an increase of $75,565,000 in adjusted gathering and processing segment margin, an increase of $14,730,000 in adjusted transportation segment margin, an increase of $886,000 in corporate and others, and the addition of $125,503,000 in contract compression segment margin.

Adjusted gathering and processing segment margin increased to $249,697,000 for the year ended December 31, 2008 from $174,132,000 for the year ended December 31, 2007. The major components of this increase were as follows:

 

 

 

$25,274,000 from a full year’s operation of our FrontStreet assets which were consolidated on June 18, 2007;

 

 

 

$19,200,000 from increased throughput and organic growth in south Texas;

 

 

 

$11,770,000 from increased throughput and organic growth in north Louisiana;

 

 

 

$9,548,000 from increased sulfur prices;

 

 

 

$7,589,000 from the operations of our Nexus assets acquired in January 2008; and

 

 

 

$4,705,000 in increased margins associated with our producer services function.

Adjusted transportation segment margin increased to $66,888,000 for the year ended December 31, 2008 from $52,158,000 for the year ended December 31, 2007. The major components of this increase were as follows:

 

 

 

$12,440,000 from increased operational efficiencies coupled with increased commodity prices; and

 

 

 

$1,684,000 from increased throughput volumes and changes in contract mix.

Contract compression segment margin was $125,503,000 in the year ended December 31, 2008, which consisted of $137,122,000 of operating revenue and $11,619,000 of direct operating cost.

 

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Operation and Maintenance. Operations and maintenance expense increased to $131,629,000 in the year ended December 31, 2008 from $58,000,000 for the corresponding period in 2007, a 127 percent increase. This increase is primarily the result of the following factors:

 

 

 

$45,326,000 related to our contract compression assets acquired in January 2008, net of intercompany eliminations;

 

 

 

$14,972,000 related to our FrontStreet assets, which are operated by a third party;

 

 

 

$8,864,000 related primarily to the gathering and processing segment associated with organic growth projects since December 31, 2007 involving compressor and other maintenance expenses in 2008;

 

 

 

$2,726,000 increase in employee-related expenses primarily related to increases in annual salaries, bonus accrual and employer benefit payments mostly in the gathering and processing segment;

 

 

 

$1,316,000 increase in utility expense due to higher commodity prices primarily in the gathering and processing segment;

 

 

 

$1,227,000 increase in contractor expense in the transportation segment due to compressor maintenance; and

 

 

 

partially offset by a $1,393,000 increase in insurance proceeds received in August 2008 ($3,134,000) versus November 2007 ($1,741,000) related to a March 2007 compressor fire in the transportation segment.

General and Administrative. General and administrative expense increased to $51,323,000 in the year ended December 31, 2008 from $39,713,000 for the same period in 2007, a 29 percent increase. In June 2007, the Partnership incurred a one-time charge of $11,928,000 associated with the vesting of all outstanding common unit options upon a change in control of our general partner. Absent this expense, general and administrative expenses increased by $23,538,000 primarily due to:

 

 

 

$16,224,000 related to our contract compression acquisition in January 2008;

 

 

 

$5,788,000 increase in employee-related expenses primarily due to hiring of new employees, employer benefit payments and bonus accruals; and

 

 

 

$958,000 increase in legal expenses.

Management Services Termination Fee. In 2008, we recorded $3,888,000 for the termination of a long-term management services contract associated with our FrontStreet acquisition.

Depreciation and Amortization. Depreciation and amortization expense increased to $102,566,000 in the year ended December 31, 2008 from $55,074,000 for the year ended December 31, 2007, an 86 percent increase. The increase was primarily due to:

 

 

 

$28,448,000 related to our contract compression assets acquired in January 2008;

 

 

 

$8,440,000 related to our FrontStreet assets which for the year ended December 31, 2008 are being depreciated over a shorter useful life as compared to 2007 and the year ended December 31, 2008 includes a full year where as the year ended December 31, 2007 only included six months of depreciation;

 

 

 

$7,428,000 related to various organic growth projects completed since December 31, 2007, primarily in the gathering and processing segment; and

 

 

 

$3,176,000 related to our Nexus assets acquired in March 2008.

Interest Expense, Net. Interest expense, net increased $11,227,000, or 22 percent, in 2008 compared to 2007. Of this increase, $26,266,000 was attributable to increased levels of borrowings partially offset by $15,039,000 primarily attributable to lower interest rates.

 

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Loss on Debt Refinancing. In the year ended December 31, 2007, we paid a $16,122,000 early repayment penalty associated with the redemption of 35 percent of our senior notes. We also expensed $5,078,000 of debt issuance costs related to the pay off of the term loan facility and the early termination of senior notes. No similar transactions occurred in 2008.

Results of Operation for HPC

Although we own a 43 percent interest in HPC, the following management discussion and analysis is for 100 percent of HPC’s consolidated results of operations. For comparative purposes only, we have combined the results of operations of RIG from January 1, 2009 to March 17, 2009, with the results of operations of HPC from inception (March 18, 2009) to December 31, 2009 to compare to RIG’s results of operations for the year ended December 31, 2008. For the years ended December 31, 2008 and 2007 the results of operations only relate to RIG.

Year Ended December 31, 2009 vs. Year Ended December 31, 2008

The table below contains key HPC performance indicators related to our discussion of the results of its operations.

 

     Year Ended December 31,              
     2009      2008    Change      Percent  
     (in thousands except percentages and volume data)         

Revenues

   $ 56,730       $ 68,921    $ (12,191    18

Cost of sales

     4,679         2,033      2,646       130   
                           

Segment margin

     52,051         66,888      (14,837    22   

Operation and maintenance

     9,697         3,540      6,157       174   

General and administrative

     5,702         9      5,693       N/M   

Loss on asset sales, net

     —           44      (44    N/M   

Depreciation and amortization

     10,962         14,099      (3,137    22   
                           

Operating income

     25,690         49,196      (23,506    48   

Interest expense

     (158      —        (158    N/M   

Other income and deductions, net

     1,335         11      1,324       N/M   
                           

Net income

   $ 26,867       $ 49,207    $ (22,340    45
                           

System inlet volumes (MMbtu/d)

     738,654         770,939      (32,285    4

 

N/M

Not meaningful

The following provides a reconciliation of segment margin to net income.

 

     Year Ended December 31,  
     2009        2008  
     (in thousands)  

Net income

   $ 26,867         $ 49,207   

Add (deduct):

       

Operation and maintenance

     9,697           3,540   

General and administrative

     5,702           9   

Loss on asset sales, net

     —             44   

Depreciation and amortization

     10,962           14,099   

Interest expense

     158           —     

Other income and deductions, net

     (1,335        (11
                   

Segment margin

   $ 52,051         $ 66,888   
                   

 

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Net income decreased to $26,867,000 in the year ended December 31, 2009 from $49,207,000 in the year ended December 31, 2008. The decrease in net income was primarily attributable to the following:

 

 

 

a decrease in segment margin of $14,837,000 primarily due to the decrease in natural gas prices and volumes;

 

 

 

an increase in operation and maintenance expense of $6,157,000 mainly resulting from an increase of $2,041,000 of contractor maintenance expenses for compression operations and the absence in 2009 of $3,134,000 in insurance reimbursement related to a compressor fire;

 

 

 

an increase in general and administrative expense of $5,693,000 primarily due to management fees paid to us by HPC;

 

 

 

an increase in other income and deductions of $1,324,000 primarily from interest earned on the cash contributions by EFS Haynesville and Alinda Investors; and were partially offset by

 

 

 

a decrease in depreciation and amortization expense of $3,137,000 primarily as a result of the valuation of RIG’s assets upon contribution to HPC as well as the revision of useful lives of the tangible assets.

Year Ended December 31, 2008 vs. Year Ended December 31, 2007

The table below contains key HPC performance indicators related to our discussion of the results of operations.

 

     Year Ended December 31,              
     2008    2007    Change      Percent  
     (in thousands except percentages and volume data)         

Revenues

   $ 68,921    $ 55,207    $ 13,714       25

Cost of sales

     2,033      2,659      (626    24   
                         

Segment margin

     66,888      52,548      14,340       27   

Operation and maintenance

     3,540      4,407      (867    20   

General and administrative

     9      —        9       N/M   

Loss on asset sales, net

     44      9      35       389   

Depreciation and amortization

     14,099      13,457      642       5   
                         

Operating income

     49,196      34,675      14,521       42   

Other income and deductions, net

     11      24      (13    54   
                         

Net income

   $ 49,207    $ 34,699    $ 14,508       42
                         

System inlet volumes (MMbtu/d)

     770,939      751,761      19,178       3

 

N/M

Not meaningful

 

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The following provides a reconciliation of adjusted segment margin to net income.

 

     Year Ended December 31,  
     2008        2007  
     (in thousands)  

Net income

   $ 49,207         $ 34,699   

Add (deduct):

       

Operation and maintenance

     3,540           4,407   

General and administrative

     9           —     

Loss on asset sales, net

     44           9   

Depreciation and amortization

     14,099           13,457   

Other income and deductions, net

     (11        (24
                   

Segment margin

   $ 66,888         $ 52,548   

Add (deduct):

       

Non-cash gain from derivatives

     —             (390
                   

Adjusted segment margin

   $ 66,888         $ 52,158   
                   

Net income increased to $49,207,000 in the year ended December 31, 2008 from $34,699,000 in the year ended December 31, 2007. The increase in net income was primarily attributable to the increase in segment margin of $14,340,000 primarily due to the increase in natural gas prices and volumes in 2008 compared to those in 2007.

HPC’s adjusted EBITDA for the years ended December 31, 2009, 2008 and 2007 are presented below.

 

     Year Ended December 31,  
     2009    2008     2007  
     (in thousands)  

Net income

   $ 26,867    $ 49,207      $ 34,699   

Add (deduct):

       

Depreciation and amortization

     10,962      14,099        13,457   

Interest expense

     158      —          —     
                       

EBITDA

   $ 37,987    $ 63,306      $ 48,156   
                       

Add (deduct):

       

Non-cash gain from derivatives

     —        —          (390

Loss on assets sales

     —        44        9   

Gain on insurance settlement

     —        (3,134     (1,741

Other expense, net

     50      33        —     
                       

Adjusted EBITDA

   $ 38,037    $ 60,249      $ 46,034   
                       

Adjusted EBITDA for the year ended December 31, 2009 comprises adjusted EBITDA of $9,581,000 related to RIG for the period from January 1, 2009 to March 17, 2009 and adjusted EBITDA of $28,456,000 related to HPC for the period from March 18, 2009 to December 31, 2009.

Cash Distributions. On January 7, 2010 the HPC management committee paid a distribution of $8,200,000, of which the Partnership received its pro-rata share of $3,526,000.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

 

 

 

cash generated from operations;

 

 

 

borrowings under our credit facility;

 

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operating lease facilities;

 

 

 

asset sales;

 

 

 

debt offerings; and

 

 

 

issuance of additional partnership units.

We expect our growth capital expenditures to be approximately $167,000,000 in 2010, inclusive of our 43 percent of the growth capital expenditures related to HPC. Our anticipated 2010 organic growth capital expenditures include $137,000,000 for the expansion of our gathering and processing facilities, $14,000,000 for additional compression for our contract compression segment, and $8,000,000 related to the corporate and others segment. We expect growth capital expenditures related to HPC for 2010 to be approximately $8,000,000 which represents our proportionate share. In total, $77,000,000 of the $167,000,000 relates to the previously approved projects related to expansions in the Haynesville Shale in the Gathering and Processing and Transportation segments.

Although we intend to move forward with our planned internal growth projects, we may further revise the timing and scope of these projects as necessary to adapt to existing economic conditions and the benefits expected to accrue to our unitholders from our expansion activities may be reduced by substantial cost of capital increases during this period.

Working Capital Surplus. Working capital is the amount by which current assets exceed current liabilities and is a measure of our ability to pay our obligations as they become due. When we incur growth capital expenditures, we may experience working capital deficits as we fund construction expenditures out of working capital until they are permanently financed. Our working capital is also influenced by current derivative assets and liabilities due to fair value changes in our derivative positions being reflected on our balance sheet. These derivative assets and liabilities represent our expectations for the settlement of derivative rights and obligations over the next 12 months, and should be viewed differently from trade accounts receivable and accounts payable, which settle over a shorter span of time. When our derivative positions are settled, we expect an offsetting physical transaction, and, as a result, we do not expect derivative assets and liabilities to affect our ability to pay expenditures and obligations as they come due. Our contract compression segment records deferred revenue as a current liability. The deferred revenue represent billings in advance of services performed. As the revenues associated with the deferred revenue are earned, the liability is reduced.

Our working capital surplus decreased to $17,468,000 at December 31, 2009 from $19,453,000 at December 31, 2008. This decrease was primarily due to the following factors:

 

 

 

a net decrease in the market value of derivative assets and liabilities of $18,571,000 due to an increase in commodity prices compared to 2008 price levels and more favorable pricing for new contracts;

 

 

 

a decrease in other current assets of $2,782,000 primarily attributable to a decrease in other prepaid assets;

 

 

 

an increase in other current liabilities of $1,794,000 which relate primarily to the interest accrual for our senior notes; and were offset by;

 

 

 

a net increase in trade accounts receivable, accrued revenues, related party receivables, trade accounts payable, accrued cost of gas and liquids, deferred revenue and related party payables of $11,934,000 primarily due to the timing of cash receipts and payments; and

 

 

 

a $9,228,000 increase in cash and cash equivalents.

Cash Flows from Operating Activities. Net cash flows provided by operating activities decreased to $143,960,000 in the year ended December 31, 2009 from $181,298,000 in the year ended December 31, 2008. The decrease is primarily due to the contribution of our RIG assets to HPC and lower commodity prices in 2009 compared to 2008.

Net cash flows provided by operating activities increased to $181,298,000 in the year ended December 31, 2008 from $79,529,000 in the year ended December 31, 2007. Cash generated from operations increased

 

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primarily due to increased total segment margin of $241,378,000, primarily due to the operating activity of our contract compression, FrontStreet and Nexus assets acquired in the first calendar quarter of 2008 and organic growth in the gathering and processing segment.

For all periods, we used our cash flows from operating activities together with borrowings under our credit facility to fund our working capital requirements, which include operation and maintenance expenses, maintenance capital expenditures and repayment of working capital borrowings. From time to time during each period, the timing of receipts and disbursements require us to borrow under our credit facility.

Cash Flows from Investing Activities. Net cash flows used in investing activities decreased to $156,165,000 in the year ended December 31, 2009 from $948,629,000 in the year ended December 31, 2008. The decrease is attributable to the absence of major acquisitions during the year and a decrease in organic growth projects, exclusive of the Haynesville Expansion Project, in 2009.

Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities or to maintain existing system volumes and related cash flows. In the year ended December 31, 2009, we incurred $136,260,000 of growth capital expenditures. Growth capital expenditures for the year ended December 31, 2009 primarily related to $87,191,000 for the fabrication of new compressor packages for our contract compression segment and $49,069,000 for organic growth projects in our gathering and processing segment. In addition, we incurred $13,700,000 related to our 43 percent of the growth capital expenditures related to HPC.

Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their useful lives. In the year ended December 31, 2009, we incurred $20,170,000 of maintenance capital expenditures.

Net cash flows used in investing activities increased to $948,629,000 in the year ended December 31, 2008 from $157,933,000 in the year ended December 31, 2007. The increase is primarily due to cash consideration paid for the contract compression, FrontStreet, and Nexus assets in the first calendar quarter of 2008 and to organic growth in the gathering and processing segment.

Cash Flows from Financing Activities. Net cash flows provided by financing activities decreased to $21,433,000 in the year ended December 31, 2009 from $734,959,000 in the year ended December 31, 2008. The decrease was primarily due to the following:

 

 

 

a decrease in net borrowing under our credit facility of $993,816,000;

 

 

 

an increase in partner distribution of $25,994,000;

 

 

 

A payment of $10,197,000 in 2009 as a deemed distribution resulted from an acquisition of assets between entities under common control in excess of historical cost; and were offset by

 

 

 

a $226,956,000 increase in net proceeds from debt issuance; and

 

 

 

a $92,225,000 increase in net proceeds from issuance of common units and Series A Preferred Units including our General Partner’s contributions to maintain its two percent interest.

Net cash flows provided by financing activities increased to $734,959,000 in the year ended December 31, 2008 from $99,443,000 in the year ended December 31, 2007 primarily due to the following:

 

 

 

an increase in net borrowings under our revolving credit facility of $585,429,000 due to increased borrowings associated with organic growth primarily in the gathering and processing segment and our contract compression, FrontStreet, and Nexus acquisitions;

 

 

 

the absence in 2008 of the 35 percent redemption of our senior notes in 2007 of $192,500,000; and partially offset by

 

 

 

a decrease in proceeds from equity issuances of $154,231,000.

 

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Capital Resources

Description of Our Indebtedness. As of December 31, 2009, our aggregate outstanding indebtedness totaled $1,014,299,000 and consisted of $419,642,000 in borrowings under our credit facility and $594,657,000 of outstanding senior notes as compared to our aggregate outstanding indebtedness as of December 31, 2008, which totaled $1,126,229,000 and consisted of $768,729,000 in borrowings under our credit facility and $357,500,000 of outstanding senior notes.

Credit Ratings. Our credit ratings as of February 23, 2010 are provided below.

 

     Moody's    Standard & Poor's

Regency Energy Partners LP

     

Outlook

   Stable    Stable

Senior notes due 2013

   B1    B

Senior notes due 2016

   B1    B

Corporate rating/total debt

   Ba3    BB-

Senior Notes due 2016. In May 2009, we issued $250,000,000 senior notes in a private placement that mature on June 1, 2016. The senior notes bear interest at 9.375 percent with interest payable semi-annually in arrears on June 1 and December 1. We paid a $13,760,000 discount upon issuance. The net proceeds were used to partially repay revolving loans under our credit facility.

At any time before June 1, 2012, up to 35 percent of the senior notes can be redeemed at a price of 109.375 percent plus accrued interest. Beginning June 1, 2013, we may redeem all or part of these notes for the principal amount plus a declining premium until June 1, 2015, and thereafter at par, plus accrued and unpaid interest. At any time prior to June 1, 2013, we may also redeem all or part of the notes at a price equal to 100 percent of the principal amount of notes redeemed plus accrued interest and the applicable premium, which equals to the greater of (1) one percent of the principal amount of the note; or (2) the excess of the present value at such redemption date of (i) the redemption price of the note at June 1, 2013 plus (ii) all required interest payments due on the note through June 1, 2013, computed using a discount rate equal to the treasury rate (as defined) as of such redemption date plus 50 basis points over the principal amount of the note.

Upon a change of control, each noteholder of senior notes due 2016 will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.

The senior notes contain various covenants that limit, among other things, our ability, and the ability of certain of our subsidiaries, to:

 

 

 

incur additional indebtedness;

 

 

 

pay distributions on, or repurchase or redeem equity interests;

 

 

 

make certain investments;

 

 

 

incur liens;

 

 

 

enter into certain types of transactions with affiliates; and

 

 

 

sell assets, consolidate or merge with or into other companies.

If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants. At December 31, 2009, we were in compliance with these covenants.

Senior Notes due 2013. In 2006, we issued $550,000,000 senior notes that mature on December 15, 2013 in a private placement. The senior notes bear interest at 8.375 percent and interest is payable semi-annually in

 

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arrears on each June 15 and December 15. In August 2007, we exercised our option to redeem 35 percent or $192,500,000 of these senior notes at a price of 108.375 percent of the principal amount plus accrued interest. Accordingly, we recorded a redemption premium of $16,122,000 and a loss on debt refinancing and unamortized loan origination costs of $4,575,000 were charged to loss on debt refinancing in the year ended December 31, 2007. Under the senior notes terms, no further redemptions are permitted until December 15, 2010.

We may redeem the outstanding senior notes, in whole or in part, at any time on or after December 15, 2010, at a redemption price equal to 100 percent of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest and liquidated damages, if any, to the redemption date.

Upon a change of control, each noteholder of senior notes due 2013 will be entitled to require us to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Our ability to purchase the notes upon a change of control will be limited by the terms of our debt agreements, including our credit facility.

The senior notes contain various covenants that limit, among other things, our ability, and the ability of certain of our subsidiaries, to:

 

 

 

incur additional indebtedness;

 

 

 

pay distributions on, or repurchase or redeem equity interests;

 

 

 

make certain investments;

 

 

 

incur liens;

 

 

 

enter into certain types of transactions with affiliates; and

 

 

 

sell assets, consolidate or merge with or into other companies.

If the senior notes achieve investment grade ratings by both Moody’s and S&P and no default or event of default has occurred and is continuing, we will no longer be subject to many of the foregoing covenants. At December 31, 2009, we were in compliance with these covenants.

Fourth Amended and Restated Credit Agreement. In February 2008, RGS’ Fourth Amended and Restated Credit Agreement (“Credit Facility”) was expanded to $900,000,000 and the availability for letters of credit was increased to $100,000,000. We also have the option to request an additional $250,000,000 in revolving commitments with ten business days written notice, provided that no event of default has occurred or would result due to such increase and all other additional conditions for the increase of the commitments set forth in the credit facility have been met. The maturity date of the credit facility is August 15, 2011.

Effective March 17, 2009, RGS amended the Credit Facility to authorize the contribution of RIG to the joint venture (HPC) and allow for a future investment of up to $135,000,000 in HPC. The amendment imposed additional financial restrictions that limit the ratio of senior secured indebtedness to adjusted EBITDA. The alternate base rate used to calculate interest on base rate loans will be calculated based on the greatest to occur of a base rate, a federal funds effective rate plus 0.50 percent and an adjusted one-month LIBOR rate plus 1.50 percent. The applicable margin shall range from 1.50 percent to 2.25 percent for base rate loans, 2.50 percent to 3.25 percent for Eurodollar loans, and a commitment fee will range from 0.375 to 0.500 percent. On July 24, 2009, RGS further amended its Credit Facility to allow for a $25,000,000 working capital facility for RIG. These amendments did not materially change other terms of the RGS revolving credit facility.

On September 15, 2008, Lehman filed a petition in the United States Bankruptcy Court seeking relief under Chapter 11 of the United States Bankruptcy Code. As a result, a subsidiary of Lehman that is a committed lender under our Credit Facility has declined requests to honor its commitment to lend. The total amount committed by Lehman was $20,000,000 and as of December 31, 2009, we had borrowed all but $10,675,000 that amount. Since

 

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Lehman has declined requests to honor its remaining commitment, our total size of the Credit Facility’s capacity has been reduced from $900,000,000 to $889,325,000. Further, if we make repayments of loans against the Credit Facility which were, in part, funded by Lehman, the amounts funded by Lehman may not be reborrowed.

RGS must pay (i) a commitment fee equal to 0.5 percent per annum of the unused portion of the revolving loan commitments, (ii) a participation fee for each revolving lender participating in letters of credit equal to 3.0 percent per annum of the average daily amount of such lender’s letter of credit exposure, and (iii) a fronting fee to the issuing bank of letters of credit equal to 0.125 percent per annum of the average daily amount of the letter of credit exposure.

The Credit Facility contains financial covenants requiring RGS and its subsidiaries to maintain debt to adjusted EBITDA and adjusted EBITDA to interest expense within certain threshold ratios. At December 31, 2009 and 2008, RGS and its subsidiaries were in compliance with these covenants.

The Credit Facility restricts the ability of RGS to pay dividends and distributions other than reimbursements to us for expenses and payment of dividends to us to the extent of our determination of available cash (so long as no default or event of default has occurred or is continuing). The Credit Facility also contains various covenants that limit (subject to certain exceptions and negotiated baskets), among other things, the ability of RGS to:

 

 

 

incur indebtedness;

 

 

 

grant liens;

 

 

 

enter into sale and leaseback transactions;

 

 

 

make certain investments, loans and advances;

 

 

 

dissolve or enter into a merger or consolidation;

 

 

 

enter into asset sales or make acquisitions;

 

 

 

enter into transactions with affiliates;

 

 

 

prepay other indebtedness or amend organizational documents or transaction documents (as defined in the Credit Facility);

 

 

 

issue capital stock or create subsidiaries; or

 

 

 

engage in any business other than those businesses in which it was engaged at the time of the effectiveness of the Credit Facility or reasonable extensions thereof.

Letters of Credit. At December 31, 2009, we had outstanding letters of credit totaling $16,257,000 under our Credit Facility. The total fees for letters of credit accrue at an annual rate of 3.125 percent, which is applied to the daily amount of letters of credit exposure.

HPC Working Capital Facility. On July 27, 2009, RIG entered into a $25,000,000 revolving credit facility that expires on July 27, 2012. We believe RIG’s working capital facility will reduce the likelihood of us having to fund 43 percent of HPC’s working capital needs in the future.

Equity offerings. On September 2, 2009, we issued 4,371,586 Series A Preferred Units at a price of $18.30 per unit, less a four percent discount of $3,200,000 and issuance costs of $176,000 for net proceeds of $76,624,000. The Series A Preferred Units are convertible to common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80,000,000 plus all accrued but unpaid distributions. The proceeds from the equity issuance were used to acquire a five percent interest in HPC from EFS Haynesville and to repay a portion of the credit facility.

On December 2, 2009 we issued 12,075,000 common units at $19.12 per unit. We received $220,318,000 in net proceeds exclusive of the general partner’s proportionate capital contribution of $4,712,000. The proceeds from the equity issuance were used to repay a portion of our credit facility borrowings.

 

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Total Contractual Cash Obligations. The following table summarizes our total contractual cash obligations as of December 31, 2009.

Operating Lease Facility. The $75,000,000 operating lease facility with Caterpillar Financial Services Corporation expired on December 31, 2009. We utilized $9,621,000 of the operating lease facility during the year ended December 31, 2009.

 

     Payment Period

Contractual Cash Obligations

   Total    2010    2011-2012    2013-2014    Thereafter
     (in thousands)

Long-term debt (including interest)(1)

   $ 1,330,330    $ 72,505    $ 538,353    $ 434,316    $ 285,156

Capital leases

     9,458      589      858      910      7,101

Operating leases

     26,105      3,838      7,227      5,065      9,975

Purchase obligations

     3,236      3,236      —        —        —  

Distributions and Redemption of Series A Preferred Units(2)

     235,629      5,836      15,563      15,563      198,667
                                  

Total(3)(4)

   $ 1,604,758    $ 86,004    $ 562,001    $ 455,854    $ 500,899
                                  

 

(1)

Assumes a constant LIBOR interest rate of 0.99 plus applicable margin (3.0 percent as of December 31, 2009) for our revolving credit facility. The principal of our outstanding senior notes ($607,500,000) bears a weighted average fixed rate of 8.787 percent.

(2)

Assumes that the Series A Preferred Units are redeemed for cash on September 2, 2029, and the annual distribution is $7,781,000.

(3)

Excludes physical and financial purchases of natural gas, NGLs, and other commodities due to the nature of both the price and volume components of such purchases, which vary on a daily and monthly basis. Additionally, we do not have contractual commitments for fixed price and/or fixed quantities of any material amount.

(4)

Excludes deferred tax liabilities of $6,996,000 as the amount payable by period can not be readily estimated in light of net operating loss carryforwards and future business plans for the entity that generates the deferred tax liability.

OTHER MATTERS

Legal. The Partnership is involved in various claims and lawsuits incidental to its business. These claims and lawsuits in the aggregate are not expected to have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Environmental Matters. For information regarding environmental matters, please read “Item 1 Business—Regulation—Environmental Matters.”

IRS Audits. The IRS mailed two “Notice of Beginning of Administrative Proceeding” to the Partnership dated January 27, 2010 stating that the IRS is commencing audits of the Partnership’s 2007 and 2008 partnership tax returns (collectively, the “NBAPs”). The Partnership understands this to be a routine audit of various items of partnership income, gain, deductions, losses and credits. The audit is in its preliminary stages so it is not known whether the IRS will propose any adjustments to the Partnership’s tax returns, whether such adjustments would be material, or how such adjustments would affect unitholders. We are making this disclosure, on behalf of our tax matters partner, to satisfy the IRS requirement that we provide a copy of the NBAPs to certain of our partners. Copies of the NBAPs are attached as exhibits hereto.

In addition, as of December 31, 2009, the IRS is conducting an audit to the tax returns of Pueblo Holdings Inc., one of our wholly-owned subsidiaries, for the tax years ended December 31, 2007 and December 31, 2008.

We, through our tax matters partner and our tax advisers, will cooperate with the IRS examiners auditing these returns. Unitholders should consult their tax advisers if they have any questions.

 

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and notes. Although these estimates are based on management’s best available knowledge of current and expected future events, actual results could be different from those estimates.

The critical judgment areas in the application of our accounting policies that currently affect our financial condition and results of operations are as follows:

Revenue and Cost of Sales Recognition. We record revenue and cost of gas and liquids on the gross basis for those transactions where we act as the principal and take title to gas that we purchase for resale. When our customers pay us a fee for providing a service such as gathering or transportation we record the fees separately in revenues. We estimate certain revenue and expenses as actual amounts are not confirmed until after the financial closing process due to the standard settlement dates in the gas industry. We calculate estimated revenues using actual pricing and measured volumes. In the subsequent production month, we reverse the accrual and record the actual results. Prior to the settlement date, we record actual operating data to the extent available, such as actual operating and maintenance and other expenses. We do not expect actual results to differ materially from our estimates.

Purchase Method of Accounting. We make various assumptions in developing models for determining the fair values of assets and liabilities associated with business acquisitions. These fair value models, developed with the assistance of outside consultants, apply discounted cash flow approaches to expected future operating results, considering expected growth rates, development opportunities, and future pricing assumptions to arrive at an economic value for the business acquired. We then determine the fair value of the tangible assets based on estimates of replacement costs less obsolescence. Identifiable intangible assets acquired consist primarily of customer contracts, customer relations, trade names, and licenses and permits. We value customer contracts using a discounted cash flow model. We value customer relations as the fair value of avoided customer churn costs compared to industry norms. We value trade names using the avoided royalty payment approach. For licenses and permits, we make assumptions regarding the period of time it would take to replace them, using a lost profits model to estimate a fair value. We determine liabilities assumed based on their expected future cash outflows. We record goodwill as the excess of the purchase price of each business unit over the sum of amounts assigned to the tangible assets and separately recognized intangible assets acquired less liabilities assumed of the business unit.

Goodwill Valuation. We review the carrying value of goodwill on an annual basis or on an as needed basis, for indicators of impairment at each reporting unit that has recorded goodwill. We determine our reporting units based on identifiable cash flows of the components of a segment and how segment managers evaluate the results of operations of the entity. Impairment is indicated whenever the carrying value of a reporting unit exceeds the estimated fair value of a reporting unit. For purposes of evaluating impairment of goodwill, we estimate the fair value of a reporting unit based upon future net discounted cash flows. In calculating these estimates, historical operating results and anticipated future economic factors, such as estimated volumes and demand for compression services, commodity prices, and operating costs are considered as a component of the calculation of future discounted cash flows. Further, the discount rate requires estimations of the cost of equity and debt financing. The estimates of fair value of these reporting units could change if actual volumes, prices, costs or discount rates vary from these estimates.

As-if Pooling of Interest Method of Accounting. We account for acquisitions where common control exists by following the as-if pooling method of accounting. Under this method of accounting, we reflect the historical balance sheet data for both the acquirer and acquiree instead of reflecting the fair market value of the acquiree’s assets and liabilities. In acquisitions of entities under common control where a minority interest is also acquired, we use the purchase method of accounting for the minority interest where the minority interest is not under common control.

 

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Equity Method Investments. The equity method of accounting is used to account for the Partnership’s interest in investments of greater than 20 percent voting stock or exerts significant influence over an investee and where the Partnership lacks control over the investee.

Depreciation Expense, Cost Capitalization and Impairment. Our assets consist primarily of natural gas gathering pipelines, processing plants, transmission pipelines, and natural gas compression equipment. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and the costs of funds used in construction. Capitalized interest represents the cost of funds used to finance the construction of new facilities and is expensed over the life of the constructed asset through the recording of depreciation expense. We capitalize the costs of renewals and betterments that extend the useful life, while we expense the costs of repairs, replacements and maintenance projects as incurred.

We generally compute depreciation using the