form10_k.htm
 



 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
þ
 
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
For the fiscal year ended December 31, 2007
OR
o
 
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
(State or other jurisdiction of
incorporation or organization)
 
16-1731691
(I.R.S. Employer
Identification No.)
1700 Pacific Avenue, Suite 2900 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 Stock Market LLC
 
Securities registered pursuant to Section 12(g) of the Act: None

 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer, accelerated filer and small reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer þ Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) o Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of June 30, 2007, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $1,004,269,000 based on the closing sale price as reported on the NASDAQ Stock Market LLC.

 
Indicate the number of outstanding units of each of the registrant’s classes of units, as of the latest practicable date.
Class
 
Outstanding at February 7, 2008
Common Units
 
40,704,020
Subordinated Units
 
19,103,896
Class D Common Units
 
7,276,506
Class E Common Units
 
4,701,034
 

DOCUMENTS INCORPORATED BY REFERENCE
 
None
 
 



REGENCY ENERGY PARTNERS LP
ANNUAL REPORT ON FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2007

TABLE OF CONTENTS
 
     
Page
       
   
Introductory Statement
  1
   
Cautionary Statement about Forward-Looking Statements
  2
Item 1
 
  3
Item 1A
 
  29
Item 1B
 
  29
Item 2
 
  29
Item 3
 
  29
Item 4
 
  29
Item 5
 
  29
Item 6
 
  31
Item 7
 
  34
Item 7A
 
  47
Item 8
 
  48
Item 9
 
  48
Item 9A
 
  48
Item 9B
 
  49
Item 10
 
  49
Item 11
 
  54
Item 12
 
  64
Item 13
 
  66
Item 14
 
  67
Item 15
 
  68


 


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, or the Partnership, 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
ASC
 
ASC Hugoton LLC, an affiliate of GECC
BBE
 
BlackBrush Energy, Inc.
Bbls/d
 
Barrels per day
BBOG
 
BlackBrush Oil & Gas, LP
Bcf
 
One billion cubic feet
Bcf/d
 
One billion cubic feet per day
BP
 
BP America Production Co., a wholly-owned subsidiary of BP plc.
BTU
 
A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM
 
CDM Resource Management, Ltd.
CDM GP
 
CDM OLP GP, LLC, the sole general partner of CDM
CDM LP
 
CDMR Holdings, LLC, the sole limited partner of CDM
CERCLA
 
Comprehensive Environmental Response, Compensation and Liability Act
CFTC   Commodities Futures Trading Commission
DOT
 
U.S. Department of Transportation
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
EPA
 
Environmental Protection Agency
FERC
 
Federal Energy Regulatory Commission
FrontStreet
 
FrontStreet Hugoton LLC
Fund V
 
Hicks, Muse, Tate & Furst Equity Fund V, L.P.
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
GSTC
 
Gulf States Transmission Corporation
HLPSA
 
Hazardous Liquid Pipeline Safety Act
HM Capital
 
HM Capital Partners LLC
HM Capital Investors
Regency Acquisition LP, HMTF Regency L.P., HM Capital and funds managed by HM Capital, including Fund V, and certain co-investors, including some of the directors and officers of the Managing GP
HMTF Gas Partners
 
HMTF Gas Partners II, LP
HMTF Regency
 
HMTF Regency L.P.
ICA      Interstate Commerce Act
IRS
 
Internal Revenue Service
LIBOR
 
London Interbank Offered Rate
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
NGA
 
Natural Gas Act of 1938
NGLs
 
Natural gas liquids
NGPA
 
Natural Gas Policy Act of 1978
NGPSA
 
Natural Gas Pipeline Safety Act of 1968, as amended
NPDES
 
National Pollutant Discharge Elimination System
NASDAQ
 
Nasdaq Stock Market, LLC
NYMEX
 
New York Mercantile Exchange
OSHA
 
Occupational Safety and Health Act
Partnership
 
Regency Energy Partners LP
Pueblo
 
Pueblo Midstream Gas Corporation
RCRA
 
Resource Conservation and Recovery Act
RGS
 
Regency Gas Services LLC
RIGS
 
Regency Intrastate Gas LLC
SEC
 
Securities and Exchange Commission
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


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 and Section 21E of the Securities Exchange Act of 1934.  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 forward-looking statements.  Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we can not 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:

§  
changes in laws and regulations impacting the midstream sector of the natural gas industry;
§  
the level of creditworthiness of our counterparties;
§  
our ability to access the debt and equity markets;
§  
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, demand for our services;
§  
weather and other natural phenomena;
§  
industry changes including the impact of consolidations and changes in competition;
§  
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.

2


PART I
Item 1.  Business
OVERVIEW.  We are a growth-oriented publicly-traded Delaware limited partnership engaged in the gathering, processing, contract compression, marketing and transportation of natural gas and NGLs.  We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas and Oklahoma.  We were formed in 2005.

We divide our operations into three 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 from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems;
§  
Transportation:  We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system; and
§  
Contract Compression:  On January 15, 2008, we acquired CDM, which provides customers with turn-key natural gas compression services.

All of our midstream assets are located in well-established areas of natural gas production that are characterized by long-lived, predictable reserves.  These areas are generally experiencing increased levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

BUSINESS STRATEGIES.  Our management team is dedicated to increasing the amount of cash available for distribution to each outstanding unit while maintaining a strong balance sheet.  We intend to achieve this by executing the following strategies:

§  
Implementing cost-effective organic growth opportunities.  We intend to build natural gas gathering assets, processing facilities, field compression, and transportation lines that will enhance our existing systems, further our ability to aggregate supply, and enable us to access premium markets for that supply.  Where applicable, we will seek to coordinate each expansion with the needs of significant producers in the area to mitigate speculative risk associated with securing through-put volumes.
§  
Maximizing the profitability of our existing assets.  We intend to increase the profitability of our existing asset base by actively controlling and reducing operating costs, identifying new business opportunities, scaling our operations by adding new volumes of natural gas supplies, and undertaking additional initiatives to enhance efficiency.
§  
Continuing to reduce our exposure to commodity price risk.  We operate our business in a manner designed to allow us to generate stable cash flows while mitigating the impact of fluctuations in commodity prices.
§  
Utilizing our relationship with GE EFS to facilitate acquisitions from third parties.  We intend to pursue strategic acquisitions of midstream assets from third parties in or near our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of those assets.  We also intend to pursue opportunities in new regions with significant natural gas reserves and high levels of drilling activity.  We believe our relationship with GE EFS will provide increased access to such opportunities.
§  
Pursuing strategic acquisitions of midstream assets from GE EFS.  GE EFS’s energy asset base is considerably larger than our own and includes midstream assets that we believe are strategically aligned with our existing operations or provide attractive operations in new regions.  GE EFS does not have any obligation to sell assets to us.  On January 8, 2008, however, we acquired FrontStreet, which owns a gas gathering system located in Kansas and Oklahoma, from affiliates of GECC.
§  
Improving our credit ratings. We are committed to achieving an investment grade rating on our debt.  Our current credit ratings are BB- and Ba3.

COMPETITIVE STRENGTHS.  We believe that we are well positioned to execute our business strategies and to compete in the natural gas gathering, processing, compression, marketing, and transportation businesses based on the following competitive strengths:

§  
Our acquisition strategy and growth opportunities will benefit from our affiliation with GE EFS.   As indicated above, we believe our affiliation with GE EFS enhances our ability to consummate accretive acquisitions and capitalize on market opportunities.
§  
We have the financial flexibility and adequate access to capital to pursue acquisition and organic growth opportunities.  We remain committed to maintaining a capital structure that will afford us the financial strength to fund expansion projects and other attractive investment opportunities.  We believe our relationship with GE increases our access to capital and enables us to pursue strategic opportunities that we might otherwise be unable to pursue.  In addition, we have sufficient liquidity under our credit facility to fund our near term growth capital requirements.
§  
We have a significant market presence in major natural gas supply areas.  We have a significant market presence in each of our operating areas, which are located in some of the largest and most prolific gas-producing regions of the United States: the Louisiana-Mississippi-Alabama Salt basin in north Louisiana, the Permian basin of west Texas, the Hugoton and Anadarko basins in the mid-continent area in Kansas and Oklahoma, the Barnett Shale basin in north Texas, the East Texas basin and Edwards, Olmos and Wilcox trends in south Texas.  Our geographical diversity reduces our reliance on any particular region, basin or gathering system.  Each of these producing regions is well-established with generally long-lived, predictable reserves, and our assets are strategically located in each of the regions.  These areas are experiencing high levels of natural gas exploration, development and production activities as a result of strong demand for natural gas, attractive recent discoveries, infill drilling opportunities and the implementation of new exploration and production techniques.

3

 
§  
We have a modern and efficient contract compressor fleet. Our highly standardized compressor fleet provides us with significant operational efficiencies and flexibility.  At December 31, 2007, 73 percent of the total available horsepower in our contract compression segment was purchased new since December 31, 2003.  We believe the young age and overall composition of our compressor fleet will result in fewer mechanical failures, lower fuel usage (a direct cost savings for our customers), and reduced environmental emissions.  In addition, in developing and maintaining our standardized fleet, we have acquired increased technical proficiency in predictive and preventive maintenance and overhaul operations on our equipment, which helps us to achieve our mechanical availability commitments.  We guarantee our customers 98 percent mechanical availability of our compression units for land installations and 96 percent mechanical availability for over-water installations.
§  
Our large horsepower contract compression installations have long-term commitments and provide stable, fee-based cash flows.  The large horsepower applications on which we focus in our contract compression business segment generally result in long-term installations with our customers, which we believe improves the stability of our cash flows.  Our contracts generally have initial terms ranging from one to five years.  We charge our customers either a fixed monthly fee for our compression services, regardless of the volume of natural gas we compress in that month, or a fee based on the volume of natural gas compressed per month.
§  
Our Regency Intrastate Pipeline System provides us with significant fee-based transportation through-put volumes and cash flow.  The Regency Intrastate Pipeline System allows us to capitalize on the flow of natural gas from producing fields in north Louisiana to intrastate and interstate markets in northeast Louisiana.  These transportation through-put volumes have limited commodity price exposure and provide us with a stable, fee-based cash flow.
§  
We have an experienced, knowledgeable management team with a proven track record.  Our senior management team has an average of over 20 years of industry related experience.  Our team’s extensive experience and contacts within the midstream industry provide a strong foundation and focus for managing and enhancing our operations, for accessing strategic acquisition opportunities and for constructing new assets.  Additionally, members of our management team have a substantial economic interest in us through an indirect 8.2 percent economic interest in the General Partner and a 1.6 percent limited partner interest.

RECENT DEVELOPMENTS
Acquisition of Nexus.  On February 22, 2008, we entered into an Agreement and Plan of Merger (the “Nexus Merger Agreement”) with Nexus Gas Partners, LLC, a Delaware limited liability company (“Nexus Member”), and Nexus Gas Holdings, LLC, a Delaware limited liability company (“Nexus”) (“Nexus Acquisition”).  The aggregate consideration to be paid is $85,000,000 in cash, subject to adjustment pursuant to customary closing adjustments.  Nexus is a midstream provider of natural gas gathering, dehydration and compression services for producers in DeSoto Parish, La., and Shelby County, Texas. The Nexus gathering system consists of 80 miles of low- and high-pressure gathering pipelines and is currently gathering more than 110 MMCF per day from approximately 500 wells.  In addition, upon consummation of the Nexus Acquisition, we will acquire Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Southern Natural Gas Company (“Sonat”).  Pursuant to the Sonat Agreement Nexus will purchase 136 miles of pipeline from Sonat that would enable the Nexus gathering system to be integrated into our north Louisiana asset base (the “Sonat Acquisition”).  The Sonat Acquisition is subject to abandonment approval by the FERC and other customary closing conditions.  Upon the closing of the Sonat Acquisition, we will pay Sonat $28,000,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, we will make an additional payment of $25,000,000 to the Nexus Member.

In connection with the closing of the Merger, $8,500,000 will be deposited with an escrow agent to secure certain indemnification obligations of Member under the Merger Agreement.  The escrow will remain in place for one year after the closing of the Merger, and the balance of the escrow upon termination of the escrow (net of any pending claims) will be released to Member.

The Nexus Acquisition is subject to approval under the Hart-Scott-Rodino Antitrust Improvements Act and other customary closing conditions. The closing is expected to occur in late first quarter or early second quarter 2008.  We anticipate funding the Merger consideration through borrowings under the existing revolving credit facility.

Acquisition of CDM.  On January 15, 2008, we acquired CDM for $695,314,000.  The total purchase price, subject to customary post-closing adjustments, paid for the partnership interests of CDM consisted of (1) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $216,869,000, (2) the payment of an aggregate of $161,945,000 in cash to the CDM Partners, and (3) the assumption of $316,500,000 in CDM’s debt obligations.  Of those Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement.  CDM provides customers with turn-key natural gas contract compression services to maximize their natural gas and crude oil production, throughput, and cash flow in Texas, Louisiana, and Arkansas.  CDM’s integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular field wide needs.  CDM is responsible for the installation and ongoing operation, service, and repair of compressors, which we modify as necessary to adapt to our customers’ changing operating conditions.  The CDM acquisition provides the Partnership with stable, fee based cash flows, a source of long-term organic growth projects, and provides synergies with the Partnership’s existing operations.  CDM’s experienced management team, retained by us to operate our contract compression segment, has demonstrated an ability to deliver strong organic growth since its inception.  CDM’s contract compression services will be reported as a separate business segment from the date of acquisition forward and will comprise the entire business segment.

4

Amendments to the Fourth Amended and Restated Revolving Credit Facility.  We have amended our credit agreement three times (September 28, 2007, January 15, 2008, and February 13, 2008) to increase commitments under our revolving credit facility to $900,000,000. The availability for letters of credit is $100,000,000.  We also have the option to request an additional $250,000,000 in revolving commitments with 10 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 fourth amended and restated credit agreement, or the credit facility, have been met. These amendments were executed to primarily provide funding for organic growth projects and acquisitions.

Acquisition of FrontStreet.  On January 7, 2008, the Partnership acquired all the outstanding equity (the “FrontStreet Acquisition”) of FrontStreet from ASC (an affiliate of GECC) and EnergyOne for $146,766,000.  The total purchase price, subject to customary post-closing adjustments, paid by the Partnership for FrontStreet consisted of (1) the issuance of 4,701,034 Class E common units of the Partnership to ASC, which were valued at $135,014,000 and (2) the payment of $11,752,000 in cash to EnergyOne.  FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.  FrontStreet’s gas gathering system has 63,500 horsepower and 1,875 miles of pipeline extending over nine counties in Kansas and Oklahoma.  The FrontStreet acquisition provides the Partnership with stable, fee based cash flows and is expected to be immediately accretive to our unitholders.

Equity Offering. On July 26, 2007, we closed an underwritten public offering of 10,000,000 common units for $32.05 per unit and, on July 31, 2007, the underwriters exercised their option to purchase 1,500,000 additional common units. We received net proceeds of $353,832,000 from these offerings.  We used a portion of these proceeds to repay amounts outstanding under the term ($50,000,000) and revolving credit facility ($178,930,000).  With the remaining proceeds and additional borrowings under the revolving credit facility, the Partnership repurchased $192,500,000, or 35 percent, of its outstanding senior notes which required us to pay an early redemption penalty of $16,122,000 in August 2007.

GE EFS acquisition of HM Capitals interests in us and resulting change in control. On June 18, 2007, Regency GP Acquirer LP, an indirect subsidiary 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.  Concurrently, Regency LP Acquirer LP, another indirect subsidiary of GECC, 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.  As a part of this acquisition, affiliates of HM Capital Partners entered into an agreement not to sell or otherwise distribute 4,692,471 of the Partnership’s common units retained by it for a period of 180 days.  In addition, a separate affiliate of HM Capital Partners entered into an agreement not to sell or otherwise distribute 3,406,099 of the Partnership’s common units retained by it for a period of one year.

GE Energy Financial Services is a unit of GECC which is an indirect wholly owned subsidiary of GE.  For simplicity, we refer to Regency GP Acquirer LP, Regency LP Acquirer LP and GE Energy Financial Services collectively as “GE EFS.” Concurrent with the Partnership's issuance of common units in July and August 2007, GE EFS and certain members of the Partnership’s management made a capital contribution aggregating to $7,735,000 to maintain the General Partner’s two percent interest in the Partnership.

Concurrent with the GE EFS acquisition of HM Capital's interest in us, eight members of the Partnership’s senior management, together with two independent directors, entered into an agreement to sell an aggregate of 1,344,551 subordinated units for a total consideration of $25,544,000 or $24.00 per unit.  Additionally, GE EFS entered into a subscription agreement with four officers and certain other management of the Partnership whereby these individuals acquired an 8.2 percent indirect economic interest in the General Partner.

The Partnership was not required to record any adjustments to reflect GE EFS’s acquisition of the HM Capital Partners’ interest in the Partnership or the related transactions (together, referred to as “GE EFS Acquisition”).

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-use markets.  It consists of natural gas gathering, compression, dehydration, processing and treating, fractionation, marketing and transportation.  Raw natural gas produced from the wellhead is gathered and delivered to a processing 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 a fractionator, which separates the NGLs into their components, such as ethane, propane, butane, isobutane and natural gasoline.  The NGL components are then sold to end users.


5

The following diagram depicts our role in the process of gathering, processing, compression, marketing and transporting natural gas.
 
Industry Graphic
 
Overview of U.S. market. According to the EIA, the midstream natural gas industry in the United States includes approximately 530 processing plants that process approximately 40 Bcf of natural gas per day and produce approximately 73 million gallons per day of NGLs.  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 domestic consumption of natural gas is expected to increase from 21.8 Tcf in 2006 to 24.3 Tcf in 2016, representing an average annual growth rate of 1.1 percent, with a slight decrease in consumption through the year 2030. During the five years ended December 31, 2005, the United States has on average consumed approximately 22.4 Tcf per year, while total marketed domestic production averaged approximately 18.9 Tcf per year during the same period.  The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

Gathering. A gathering system typically consists of a network of small diameter pipelines and, if necessary, a compression system which together collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.  We own and operate large gathering systems in five geographic regions of the United States.

Compression. Gathering systems are operated at design pressures that seek to maximize the total through-put volumes from all connected wells.  Since wells produce at progressively lower field pressures as they age, the raw natural gas must be compressed to deliver the remaining production against a higher pressure that exists in the connected gathering system.  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 gas that no longer naturally flows into a higher pressure downstream pipeline to be brought to market.  Field compression is typically used to lower the entry pressure, while maintaining or increasing the exit pressure of a gathering system to allow it to operate at a lower receipt pressure and provide sufficient pressure to deliver gas into a higher pressure downstream pipeline.  We operate more than 700,000 horsepower of compression in Texas, Louisiana, Oklahoma, Kansas and Arkansas.

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, gas and amine are separated, and the impurities are removed from the amine by heating.  The treating plants are sized by the amine circulation capacity in terms of gallons per minute.  We own and operate natural gas processing and/or treating plants in five geographic regions.

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 varying amounts of heavier hydrocarbon components, or NGLs.  Natural gas is described as lean or rich depending on its content of NGLs.  Most natural gas produced by a well is not suitable for long-haul pipeline transportation or commercial use because it contains NGLs and impurities.  Natural gas processing not only removes unwanted NGLs that would interfere with pipeline transportation or use of the natural gas, but also extracts hydrocarbon liquids that can have higher value as NGLs.  Removal and separation of individual hydrocarbons by processing is possible because of differences in weight, boiling point, vapor pressure and other physical characteristics.  We own and operate natural gas processing and/or treating plants in five geographic regions.

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.

Marketing. Natural gas marketing involves the sale of the pipeline-quality natural gas either produced by processing plants or purchased from gathering systems or other pipelines.  We perform a limited natural gas marketing function for our account and for the accounts of our customers.

Transportation. Natural gas transportation consists of moving pipeline-quality natural gas from gathering systems, processing plants and other pipelines and delivering it to wholesalers, utilities and other pipelines.  We own and operate the Regency Intrastate Pipeline system, an intrastate natural gas pipeline system located in north Louisiana.  We also own a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

6

GATHERING AND PROCESSING OPERATIONS
General. We operate significant gathering and processing assets in five geographic regions of the United States: north Louisiana, the mid-continent, 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 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, we remove any impurities in the raw natural gas stream and extract the NGLs.  Our gathering and processing operations are located in areas that have experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies.

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 through interstate or intrastate gas transportation pipelines.

The following table sets forth information regarding our gathering systems and processing plants as of December 31, 2007.

                         
Region
 
Pipeline Length (Miles)
   
Plants
   
Compression (Horsepower)
   
Through-put Volume Capacity (MMcf/d)
 
North Louisiana
    600       4       39,100       790  
East Texas
    371       1       25,665       215  
South Texas
    623       2       27,828       555  
West Texas
    750       1       47,000       325  
Mid-Continent
    3,470       1       105,630       437  
Total
    5,814       9       245,223       2,322  

 
 
The following map depicts the geographic areas of our operations.
 
System Map
 
 

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North Louisiana Region. Our north Louisiana region includes:
§  
the Dubach and Lisbon processing plants;
§  
the Dubach/Calhoun/Lisbon gathering system, which is a large integrated natural gas gathering and processing system located primarily in four parishes of north Louisiana; and
§  
the Elm Grove and Dubberly refrigeration plants.

This system is located in active drilling areas in north Louisiana.  Through our Dubach/Calhoun/Lisbon gathering system and its interconnections with our Regency Intrastate Pipeline system in north Louisiana described in “—Transportation Operations,” we offer producers wellhead-to-market services, including natural gas gathering, compression, processing, marketing and transportation.

Natural Gas Supply. The natural gas supply for our north Louisiana gathering systems is derived primarily from natural gas wells located in Claiborne, Union, Lincoln and Ouachita Parishes in north Louisiana.  This area has experienced significant levels of drilling activity, providing us with opportunities to access newly developed natural gas supplies.  Natural gas production in this area has increased as a result of the additional drilling, which includes deeper reservoirs in the Cotton Valley and Hosston trends.

Dubach/Lisbon/Calhoun Gathering System. The Dubach/Lisbon/Calhoun gathering system consists of 600 miles of natural gas gathering pipelines ranging in size from two inches to 10 inches in diameter.  The system gathers raw natural gas from producers and delivers it to either the Dubach or Lisbon processing plant for processing.  The remainder of the raw natural gas is lean natural gas, which does not require processing and is delivered directly to interstate pipelines and our Regency Intrastate Pipeline system.


Dubach and Lisbon Processing Plants. The Dubach processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Dubach and Calhoun gathering systems.  The Lisbon plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Lisbon gathering system.  These plants were acquired by us in 2003, were originally constructed in 1980 and were reassembled on their present locations in 1994 and 1996, respectively.

Elm Grove and Dubberly Refrigeration Plants. The Elm Grove and Dubberly refrigeration plants process raw natural gas located in Bossier and Webster parishes in northeastern Louisiana.  Elm Grove was placed into service in May 2006 and Dubberly was placed into service in December 2006.

East Texas Region.  Our east Texas gathering assets gather, compress, and dehydrate natural gas.  Natural gas produced in this region contains high levels of hydrogen sulfide. Our east Texas region includes:

§  
the Eustace Gathering System, a large integrated natural gas gathering and processing system located in Rains, Wood, Van Zandt and Henderson Counties; and
§  
the Como Gathering System, a smaller integrated natural gas gathering and processing system located in Franklin, Wood, Hopkins and Rains Counties.

Both the Eustace and Como gathering systems deliver natural gas to into the Eustace processing plant that is equipped with a sulfur removal unit.

Natural Gas Supply. The natural gas supply for our east 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.

Eustace Processing Plant. The Eustace processing plant is a cryogenic natural gas processing plant that was constructed in its current location in 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 gas at the plant outlet and produces sulfur.

South Texas Region.  The south Texas gathering assets gather, compress, and dehydrate natural gas.  Some of the natural gas produced in this region can have significant hydrogen sulfide and carbon dioxide content.  These systems are connected to processing and treating facilities that include an acid gas reinjection well.  Our south Texas region primarily includes the following natural gas gathering systems:

§  
the LaSalle Gathering System, a large natural gas gathering system located in LaSalle and Webb counties.  Gas from this system is processed by a third party.
§  
the Pueblo Gathering System, a large integrated natural gas gathering, treating, and processing system located in Karnes and Atascosa counties.  Gas from this system is treated and processed at our Fashing Plant.  We have plans to connect this system to our Tilden treating plant during 2008;
§  
the Tilden Gathering System, a large integrated natural gas gathering and treating system located in McMullen, Atascosa, Frio and LaSalle Counties in south Texas and flows into the Tilden treating plant; and
§  
the Palafox Gathering System, a small gathering system located in Dimmitt and Webb counties, Texas. The natural gas gathered by this system is delivered to a third party for processing.

Natural Gas Supply. 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.

Tilden Treating Plant. The Tilden Treating Plant is a natural gas treating plant constructed on its current location in 1981.  It includes inlet 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.  An additional 55 MMcf/d amine treating unit is currently inactive.  This plant removes hydrogen sulfide from the natural gas stream, which in this region often contains a high concentration of hydrogen sulfide, recovers condensate, delivers pipeline quality gas at the plant outlet and reinjects acid gas.

West Texas Region. The system covers four Texas counties surrounding the Waha Hub, one of Texas’ major natural gas market areas.  Through our Waha gathering system, we offer producers wellhead to market services.  As a result of the proximity of this 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.  Our west Texas region includes the Waha gathering system and the Waha processing plant.
 
Natural Gas Supply. The natural gas supply for the Waha gathering system is derived primarily from natural gas wells located in four counties in west Texas near the Waha Hub.  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.

 

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Waha Gathering System. The Waha gathering system consists of 750 miles of natural gas gathering pipelines ranging in size from three inches in diameter to 24 inches in diameter.  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 it requires.

Waha Processing Plant. The Waha processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Waha gathering system.  This plant was constructed in 1965, and, due to recent upgrades to state of the art cryogenic processing capabilities, it 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 in our Waha gathering system before moving the natural gas to the processing plant.  The acid gas is reinjected.

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 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 increase the total through-put volumes from the connected wells.  Wellhead pressures are therefore adequate to access the gathering lines without the cost of wellhead compression.  In addition, we process natural gas from the Mocane-Laverne gathering system at our Mocane processing plant.

Natural Gas Supply. Our mid-continent systems are located in two of the largest and most prolific natural gas producing regions in the United States, including the Hugoton Basin in southwest Kansas and the Anadarko Basin in western Oklahoma.  These mature basins have continued to provide generally long-lived, predictable reserves.  Recent increases in production in these areas have been driven primarily by continued infill drilling, compression enhancements, and advanced well bore completion technology.  In addition, the application of 3-D seismic technology in these areas has yielded better-defined reservoirs for continuing development of these basins.

Hugoton Gathering System.  On January 7, 2008, the Partnership completed its acquisition of FrontStreet which owns the Hugoton gathering system, consisting of five compressor stations with over 63,500 horsepower and 1,875 miles of pipeline extending over nine counties in Kansas and Oklahoma.  This system is operated by a third party.

Lakin Gathering System. The Lakin gathering system is located in southwestern Kansas.  It consists of 850 miles of natural gas gathering pipelines ranging in size from two inches to 20 inches in diameter.  Substantially all of the raw natural gas gathered by the Lakin gathering system is delivered to a third party’s processing plant.

Mocane-Laverne Gathering System. The Mocane-Laverne gathering system is located in Beaver and Harper counties in the Oklahoma panhandle and Meade County in southwestern Kansas.  It consists of 500 miles of natural gas gathering pipelines ranging in size from two inches to 24 inches in diameter.  The system gathers raw natural gas from producers and delivers it for processing to the Mocane processing plant.

Greenwood Gathering System. The Greenwood gathering system is primarily located in Morton and Stanton Counties in southwestern Kansas.  It consists of 250 miles of natural gas gathering pipelines ranging in size from four inches to 20 inches in diameter.  The raw natural gas gathered by this system is delivered to a third party’s processing plant.  We pay the third party a fee to process the gas for our account.

Mocane Processing Plant. The Mocane processing plant is a cryogenic natural gas processing plant that processes raw natural gas gathered on the Mocane-Laverne gathering system.  This plant was constructed in 1975 and acquired by us in 2003.

Other. We also own the Lakin processing plant, a cryogenic processing plant with nitrogen rejection and helium recovery capabilities.  This plant, which is currently idle, has a capacity of 80 MMcf/d.  The plant was constructed in 1995 and was acquired by us in 2003.  We are currently evaluating opportunities to utilize the Lakin processing plant, which may include connecting a new source of supply to the plant or moving the plant to another area.

TRANSPORTATION OPERATIONS
Regency Intrastate Pipeline. We own and operate a 320-mile intrastate natural gas pipeline system, known as the Regency Intrastate Pipeline system, in north Louisiana extending from Caddo Parish to Franklin Parish in northern Louisiana.  This system, with pipeline ranging from 12 to 30 inches in diameter, includes total system capacity of 910 MMcf/d, 28,375 horsepower of compression and our Haughton Plant, a 35 MMcf/d refrigeration plant.  Natural gas generally flows from west to east on the pipeline from wellhead connections or connections with other gathering systems.  The Regency Intrastate Pipeline system transports natural gas produced from the Vernon field, the Elm Grove field and the Sligo field, which are three of the four largest natural gas producing fields in Louisiana. Our transportation operations are located in areas that have experienced significant levels of drilling activity providing us with opportunities to access newly developed natural gas supplies.
 
Gulf States Transmission.  Our interstate pipeline 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.
 
On February 6, 2008, one of the interstate pipelines, Columbia Gulf, which our RIGS pipeline interconnects with, lost approximately 68,000 horsepower of compression due to a tornado.  We have not experienced a material impact to our operations or results of operations.  We continue to monitor this situation and will modify our operations if necessary.
 
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CONTRACT COMPRESSION OPERATIONS
The natural gas contract compression services we provide, subsequent to our acquisition of CDM, 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, and Arkansas.

The following table set forth certain information regarding CDM’s revenue generating natural gas compressor horsepower as of December 31, 2007.
 
       
Percentage of
     
Horsepower
 
Total Revenue
 
Revenue Generating
 
Number of
 
Range
 
Generating Horsepower
 
Horsepower
 
Units
 
0-499
 
                                41,958
 
7%
 
            252
 
500-999
 
                                61,609
 
11%
 
              99
 
1,000+
 
                              464,660
 
82%
 
            307
 
   
                              568,227
 
100%
 
            658
 

OUR CONTRACTS
Gathering and Processing Contracts. We contract with producers to gather raw natural gas from individual wells or central delivery 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 delivery 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 for a fee.  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.”  During the year ended December 31, 2007, purchases from KCS Resources, Inc. were 16 percent of the volumes underlying the cost of gas and liquids on our consolidated statement of operations.

For the above described contracts, the margin by product and percentage were as follows for the year ended December 31, 2007.
 
Margin by Product
 
Percent
 
Net Fee
    43 %
NGL
    37  
Gas
    10  
Condensate
    8  
Helium and Sulfur
    2  
Total
    100 %
 
 
Transportation Contracts.
Fee Transportation Contracts. We provide natural gas transportation services on the Regency Intrastate Pipeline pursuant to contracts with natural gas shippers.  These contracts are all fee-based.  Generally, our transportation services are of two types: firm transportation and interruptible transportation.  When we agree to provide firm transportation service, we become 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 our part, 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 we agree to provide interruptible transportation service, we become obligated to transport natural gas nominated and actually delivered by the shipper only to the extent that we have available capacity.  The shipper pays no reservation charge for this service but pays a commodity charge for quantities actually shipped.  We provide our transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with the FERC with respect to transportation authorized under Section 311 of the NGPA.

Merchant Transportation Contracts. We perform a limited merchant function on our Regency Intrastate Pipeline system.  We purchase natural gas from producers or gas marketers at receipt points on our system at a price adjusted to reflect our transportation fee and transport that gas to delivery points on our system where we sell the natural gas at market price.  We regard the total 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 same index price on the date of settlement.

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Contract 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 pay either a fixed monthly fee, or 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 customer 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. The natural gas gathering, processing, contract compression, marketing, and transportation businesses are highly competitive.  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 in each region include:

§  
North Louisiana:  CenterPoint Energy Gas Marketing Company; PanEnergy Louisiana Intrastate, LLC (Pelico)
§  
East Texas:  Enbridge Energy Partners LP
§  
South Texas: Enterprise Products Partners LP, Duke Energy Field Services, L.P
§  
West Texas:  Southern Union Gas Services, Enterprise Products Partners LP
§  
Mid-Continent:  Duke Energy Field Services, L.P.; ONEOK Energy Marketing and Trading, L.P.; Penn Virginia Corporation

Transportation.  Competition in natural gas transportation is characterized 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, we face major competition from CenterPoint Energy Gas Marketing Company, Gulf South Pipeline, L.P., and Texas Gas Transmission, LLC.

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 Hanover Compressor Company, Universal Compression Holdings, Inc. (or Exterran Holdings, Inc. following its merger with Hanover Compressor Company), Universal Compression Partners, L.P., Compressor Systems, Inc., USA Compression 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 risk, we have implemented a risk management program under which we seek to
§  
match sales prices of commodities (especially natural gas) 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 consequence 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 natural gas and NGL 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 marketing 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 purchasing a series of swap contracts for individual NGLs.  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.

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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.  Our indirect exposure to short-term volatility in natural gas and crude oil commodity prices is mitigated because natural gas and crude oil production, rather than exploration, is the primary demand driver for our contract compression services, and because our focus on field-wide applications reduces our dependence on individual well economics.

REGULATION
Industry Regulation
Intrastate Natural Gas Pipeline Regulation. Pursuant to Section 311 of the NGPAS, RIGS transports interstate natural gas in Louisiana for many of its shippers.  To the extent that our Regency Intrastate Pipeline system transports natural gas in interstate service, its rates, terms and conditions of service are subject to the jurisdiction of the FERC.  Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of “fair and equitable” rates are subject to refund with interest.  NGPA Section 311 rates deemed fair and equitable by the FERC are generally analogous to the cost-based rates that the FERC deems “just and reasonable” for interstate pipelines under the NGA. RIGS is required to file triennial rate petitions either justifying its existing rates or requesting new rates.  RIGS’ most recent FERC-approved Section 311 maximum rates were established in 2005 effective from May 1, 2005 to May 1, 2008.  These rates were set for firm transportation at $0.15 per MMBtu reservation charge, with a $0.05 MMBtu daily commodity charge, and for interruptible transportation at $0.20 per MMBtu.  RIGS is obligated to file its next Section 311 rate case no later than May 1, 2008.  Any failure on our part:

§  
to observe the service limitations applicable to transportation service under Section 311,
§  
to comply with the rates approved by the FERC for Section 311 service,
§  
to comply with the terms and conditions of service established in our FERC-approved Statement of Operating Conditions, or
§  
to comply with applicable FERC regulations, the NGPA or certain state laws and regulations

could result in an alteration of our jurisdictional status or the imposition of administrative, civil and criminal penalties, or both.

RIGS is also subject to regulation by various agencies of the State of Louisiana.  Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation 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.  The distinction between FERC-regulated transmission facilities and intrastate facilities has been the subject of litigation, so the classification and regulation of RIGS as an intrastate pipeline may be subject to change based on future determinations by the FERC, the courts or the U.S. Congress.

FERC has adopted new market-monitoring and annual reporting regulations applicable to many intrastate pipelines.  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 not final, the monitoring and annual reporting mandated by these regulations could require intrastate pipelines to incur increased costs and administrative burdens.  FERC has also proposed to require both interstate and certain major non-interstate pipelines to post, on a daily basis, capacity, scheduled flow information and actual flow information, which regulations could subject us to further costs and administrative burdens.

Interstate Natural Gas Pipeline Regulation. The 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.  The 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;
§  
depreciation and amortization policies;
§  
accounting rates for ratemaking purposes;
§  
acquisition and disposition of facilities;
§  
initiation and discontinuation of services;
§  
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.

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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 the FERC has used to establish a pipeline’s status as a gatherer not subject to FERC 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 the FERC, the courts or the U.S. Congress.

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 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 and legislation pertaining to these matters may be considered or adopted from time to time.  We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

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 FERC regulates the tariff rates for interstate NGL transportation and imposes reporting and a number of other requirements.  Our NGL transportation tariff is required to be just and reasonable and not unduly discriminatory or confer any undue preference.  FERC has established an indexing system for transportation rates for oil, NGLs and other products that allows for an annual inflation-based increase in the cost of transporting these liquids to the shipper.  The implementation of these regulations has not had a material adverse effect on our results of operations.  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.  We also have a Texas common carrier pipeline that provides intrastate transportation of crude oil subject to a local tariff approved by and on file with the TRRC.  This pipeline is subject to a number of TRRC regulatory requirements governing rates and terms and conditions of service.

Sales of Natural Gas. Our ability to sell gas in interstate markets is subject to FERC authority and its rules prohibiting natural gas market manipulation.  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 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 is continually proposing and implementing new rules and regulations affecting interstate transportation.  These initiatives also may affect the intrastate transportation of natural gas under certain circumstances.  The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry.  We do not believe that we will be affected by any such FERC action in a manner materially differently than other natural gas companies with whom we compete.

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.
 

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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 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 costs 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.

Under an omnibus agreement, Regency Acquisition LP, the entity that formerly owned our General Partner, agreed to indemnify us in an aggregate amount not to exceed $8,600,000, generally for three years after February 3, 2006, for certain environmental noncompliance and remediation liabilities associated with the assets transferred to us and occurring or existing before that date.  For a discussion of the omnibus agreement, please read “Item 13 — Certain Relationships and Related Transactions, and Director Independence — Omnibus Agreement.”

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 control 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.

We also generate both hazardous and nonhazardous wastes that are subject to requirements of the federal RCRA, and comparable state statutes.  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.  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.  It is possible, however, 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.

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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, we are indemnified for certain environmental matters. Those provisions include an indemnity by the El Paso sellers against a variety of environmental claims for a period of five years up to an aggregate of $84,000,000.  The agreement also included an escrow of $9,000,000 relating to claims, including environmental claims. In response to our submission of a claim to the El Paso sellers for a variety of environmental defects at these assets, the El Paso sellers have agreed to maintain $5,400,000 in the escrow account to pay any claims for environmental matters ultimately deemed to be covered by their indemnity.  This amount represents the upper end of the estimated remediation cost calculated by Regency based on the results of its investigations of these assets.

Since the time of this agreement, a Final Site Investigation Report has been prepared.  Based on this additional investigation, environmental issues exist with respect to four facilities, including the two subject to accepted claims and two of our processing plants. The estimated remediation costs associated with the processing plants aggregate $2,750,000.  We believe that any of our obligations to remediate the properties is subject to the indemnity under the El Paso PSA, and we intend to reinstate the claims for indemnification for these plant sites.

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

West Texas Assets.  A Phase I environmental study was performed on our west Texas assets in connection with our investigation of those assets prior to our purchase of them 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.  We believe that the likelihood that we will be liable for any significant potential remediation liabilities identified in the study is remote. At the time of the negotiation of the agreement to acquire the west Texas assets, management of RGS obtained an insurance policy against specified risks of environmental claims (other than those items known to exist).  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.

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 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 becoming 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 Federal Water Pollution Control Act of 1972, as renamed and amended as 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.  The Clean Water Act and comparable state laws and their respective regulations provide for administrative, civil and criminal penalties for discharges of unauthorized pollutants into the water and also provide for penalties and liability for the costs of removing spills from such 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 could cause us to incur additional costs or to become subject to operating restrictions or bans in the affected areas.

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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.

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.  We believe, based on current information, that any costs that we may incur relating to environmental matters will not adversely affect us.  We cannot be certain, however, 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.
 
TCEQ Notice of Enforcement.  On February 15, 2008, the Texas Commission on Environmental Quality, or TCEQ, sent us a notice of enforcement, or NOE, relating to the air emissions at our Tilden processing plant.  The NOE relates to 15 alleged violations occurring during the period from March 2006 through July 2007 of the emissions event reporting and recordkeeping requirements of the TCEQs rules.  Specifically, it is alleged that one of our subsidiaries failed to report, using the TCEQ’s electronic data base for emissions events, 15 emissions events within 24 hours of the incident, as required.  These events occurred during times of failure of the Tilden plant sulphur recovery unit or ancillary equipment  and resulted in the flaring of acid gas.  Of these events, one relates to an alleged release of nearly 6 million pounds of sulphur dioxide and 64,000 pounds of hydrogen sulphide, 11 related to less than 2,500 pounds of sulphur dioxide and three related to more than 2,500 and less than 40,000 pounds of sulphur dioxide (including two releases of 126 and 393 pounds of hydrogen sulphide).  In 2007, the subsidiary completed construction of an acid gas reinjection unit at the Tilden plant and permanently shut down the Sulphur Recovery Unit
 
All these emission incidents were reported by means of fax or telephone to the TCEQ pursuant to an informal procedure established with the TCEQ by the prior owner of the Tilden plant and, indeed, the subsidiary paid the emission fines in connection with all the incidents.  Using that procedure, all except one were timely.  The TCEQ has, prior to our subsidiary acquiring the Tilden facility, established its electronic data base for emissions events, but the subsidiary did not report using that electronic facility.  It is the failure to report each incident timely using the electronic reporting procedure that is the subject of the NOE.  Representatives of the Partnership are scheduled to meet with the staff of the TCEQ in the near future regarding the NOE.  Management of the General Partner does not expect the NOE to have a material adverse effect on its results of operations or financial condition.

EMPLOYEES
As of December 31, 2007, our General Partner employs 317 employees, of whom 182 are field operating employees and 135 are mid-and senior-level management and staff.  None of these employees is 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.  With our CDM acquisition, we now employ 609 employees.

AVAILABLE INFORMATION
The Partnership files annual and quarterly financial 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, Room 1580, 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 ..

The Partnership makes its SEC filings available to the public, free of charge and as soon as practicable after they are filed with the SEC, through its Internet site 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 Securities Exchange Act of 1934. References to our website addressed in this report are provided as a convenience and do not constitute, or should 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 on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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the fees we charge and the margins we realize for our services and sales;
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the prices of, level of production of, and demand for natural gas and NGLs;
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the volumes of natural gas we gather, process and transport;
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the level of our operating costs, including reimbursement of fees and expenses of our general partner; and
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prevailing economic conditions.

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:

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our debt service requirements;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions contained in our debt agreements;
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the level of capital expenditures we make;
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the cost of acquisitions, if any; and
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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 and not solely on profitability, which will be affected by non-cash items.  As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

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:

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operating a significantly larger combined organization and adding operations;
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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, such as the assets acquired in the CDM acquisition;
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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;
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the loss of significant producers or markets or key employees from the acquired businesses;
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the diversion of management’s attention from other business concerns;
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the failure to realize expected profitability, growth or synergies and cost savings;
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coordinating geographically disparate organizations, systems, and facilities; and
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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.

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, the ability of producers to obtain necessary drilling and other governmental permits and regulatory changes.  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.

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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 services.

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.  For example, purchases from KCS Resources, Inc. made up 16 percent of the volumes underlying the cost of gas and liquids on our consolidated statement of operations during the year ended December 31, 2007.

Our contract compression segment depends on particular suppliers and is vulnerable to product 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 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.

Natural gas, NGLs and other commodity prices are volatile, and a reduction 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.  NGL 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 we expect this volatility to continue.  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:

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the impact of weather on the demand for oil and natural gas;
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the level of domestic oil and natural gas production;
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the availability of imported oil and natural gas;

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actions taken by foreign oil and gas producing nations;
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the availability of local, intrastate and interstate transportation systems;
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the availability and marketing of competitive fuels;
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the impact of energy conservation efforts; and
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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 an agreed percentage of the proceeds (in cash or in-kind) from the sale at market prices of pipeline-quality gas and NGLs resulting from our processing activities.  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 NGL prices, it is more profitable for us to process natural gas under keep-whole arrangements.  When natural gas prices are high relative to NGL 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.

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 the Gathering and Processing segment, we are a seller of NGLs and are exposed to commodity price risk associated with downward movements in NGL prices.  As a result of the volatility of NGL prices, we have executed swap contracts settled against ethane, propane, normal butane, natural gasoline and west Texas intermediate crude market prices.  We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.  Also, we may seek to limit our exposure to changes in interest rates by using financial derivative instruments and other hedging mechanisms from time to time.  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.

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.  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 revenues 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 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 finance the construction or modification project and on our ability to hire, train, and retain qualified personnel to manage and operate these facilities when completed.

19

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.

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 and petrochemical 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.

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.

If third-party pipelines interconnected to our processing plants become unavailable to transport NGLs, our cash flow and results of operations could be adversely affected.

We depend upon third party pipelines that provide delivery options to and from our processing plants for the benefit of our customers.  If any of these pipelines become unavailable to transport the NGLs produced at our related processing plants, we would be required to find alternative means to transport the NGLs from our processing plants, which could increase our costs, reduce the revenues we might obtain from the sale of NGLs, or reduce our ability to process natural gas at these plants.

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.  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, 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;
§  
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.

20

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 $1,200,000 between 2008 and 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 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.

Our interstate gas transportation operations, including Section 311 service performed by its intrastate 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 interstate or Section 311 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.  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.  In addition, FERC regulates the rates, terms and conditions of service with respect to Section 311 transportation service provided by RIGS.  Any failure on our part to comply with applicable FERC administered statutes, rules, regulations and orders could, in the case of RIGS, result in an alteration of our jurisdictional status, or could result in the imposition of administrative, civil and criminal penalties, or both.  In addition, FERC has authority to alter its rules, regulations and policies to comply with its statutory authority.  We cannot give any assurance regarding the likely future regulations under which RIGS or GSTC will operate its interstate transportation business or the effect such regulation could have on our business, results of operations, or ability to make distributions.


21

As a limited partnership entity, we may be disadvantaged in calculating its cost-of-service for rate-making purposes.

Under current policy applied under the NGA, the FERC permits interstate 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 public utility 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 the FERC on a case-by-case basis.  In connection with its upcoming Section 311 rate case required to be initiated on or before May 1, RIGS may be required to demonstrate the extent to which inclusion of an income tax allowance in Regency’s 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.

In addition, on July 19, 2007, FERC issued a proposed policy statement regarding the composition of proxy groups for determining the appropriate returns on equity for interstate natural gas and oil pipelines.  The proposed policy statement would permit the inclusion of master limited partnerships (MLPs) in the proxy group for purposes of calculating returns on equity under the discounted cash flow analysis, a change from its prior view that MLPs had not been shown to be appropriate for such inclusion.  Specifically, FERC proposes that MLPs may be included in the proxy group provided that the discounted cash flow analysis recognizes as distributions only the pipeline’s reported earnings and not other sources of cash flow subject to distribution.  According to the proposed policy statement, under the discounted cash flow analysis, the return on equity is calculated by adding the dividend or distribution yield (dividends divided by share/unit price) to the projected future growth rate of dividends or distributions (weighted one-third for long-term growth of the economy as a whole and two-thirds short term growth as determined by analysts’ five-year forecasts for the pipeline).  The determination of which MLPs should be included will be made on a case-by-case basis, after a review of whether an MLPs earnings have been stable over a multi-year period.  FERC proposes to apply the final policy statement to all natural gas rate cases that have not completed the hearing phase as of the date FERC issues the final policy statement.  Comments on the proposed policy statement were filed by numerous parties, and on January 8, 2008, FERC held a technical conference to discuss the proposed policy.  FERC’s proposed policy statement is subject to change based on filed comments and the technical conference.  Therefore, we cannot predict the scope or outcome of the final policy statement.  If the hearing phase of the Section 311 rate case RIGS is required to file by May 1, 2008, has not been completed as of the date FERC issues its final policy statement, and FERC determines to apply the policy statement to Section 311 transportation rates, application of the statement might affect RIGS ability to achieve a reasonable level of equity return in its Section 311 rate proceeding.

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

Our natural gas gathering 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.  FERC’s policies and practices, including, for example, its policies on open access transportation, ratemaking, capacity release, and market center promotion, indirectly affect intrastate markets.  In recent years, FERC has pursued pro-competitive regulatory policies.  However, with the passage of the Energy Policy Act of 2005, the FERC has sought to expand its oversight of natural gas purchasers, gatherers and intrastate pipelines by developing new market monitoring and market transparency rules.  FERC recently issued a notice of proposed rulemaking that would require posting of available capacity, scheduled capacity and actual flows on non-interstate pipelines, including gathering companies and intrastate pipelines.  We cannot predict the outcome of this proposed rulemaking or how the FERC will approach future matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity.  In addition, the distinction between FERC-regulated transmission service and federally unregulated gathering services 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 lines 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.  States in which we operate have adopted complaint-based regulation of oil and natural gas gathering activities, which allows oil and natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to oil and natural gas gathering access and rate discrimination.

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.

22

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 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, 2007 was 51 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 issues, 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 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.

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

If a change of control (as defined in the indenture) 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 the indenture governing the senior notes, a change of control could also have occurred under the senior secured credit facilities, 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 indenture for our debt, we may not have sufficient funds to pay the purchase price of all debt that we are required to purchase or repay.

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 continue to be 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.

23

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 these entities on our behalf;
§  
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 affiliates of GECC may compete directly with us.

GE EFS and affiliates of GECC are not prohibited from owning assets or engaging in businesses that compete directly or independently with us.  GE EFS and affiliates of GECC currently own various midstream assets and conduct midstream businesses that may potentially compete with us.  In addition, GE EFS and affiliates of GECC 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 you.

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.

24

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

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

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 the common units will 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.

The unitholders are currently unable to remove the General Partner without its consent because the General Partner and its affiliates own sufficient units to be able to prevent its removal.  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 7, 2008, our General Partner owns 31.2 percent of the total of our common and subordinated units.  Moreover, if our General Partner is removed without cause during the subordination period and units held by GE EFS are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on the common units will be extinguished.  A removal of the General Partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests.

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 the 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 to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders.  Furthermore, our partnership agreement does not restrict the ability of 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. 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;
§  
because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;
§  
the relative voting strength of each previously outstanding unit may be diminished; and
§  
the market price of the common units may decline.

25

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

Pursuant to agreements with investors in private placements or acquisitions, we have filed registration statements on Form S-3 registering sales by selling unitholders of an aggregate of 11,881,000 of our common units, and have outstanding obligations to file registration statements with respect to 11,978,000 common units, including the 7,276,506 common units to be issued upon conversion of Class D units we issued to the sellers in the CDM acquisition and the 4,701,034 common units to be issued upon conversion of Class E units we issued to the sellers in the FrontStreet acquisition.

Substantially all of the common units so registered remain unsold pursuant to these registration statements.  If investors holding these units were to dispose of a substantial portion of these units in the public market, whether in a single transaction or series of transactions, it could temporarily reduce the market price of our outstanding common units.  In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our 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 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, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment.  You may also incur a tax liability upon a sale of your units.  As of February 7, 2008, our General Partner owns 31.2 percent of the total of our common and subordinated units.

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states.  The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.  In most states, a limited partner is only liable if he participates in the “control” of the business of the partnership.  These statutes generally do not define control, but do permit limited partners to engage in certain activities, including, among other actions, taking any action with respect to the dissolution of the partnership, the sale, exchange, lease or mortgage of any asset of the partnership, the admission or removal of the general partner and the amendment of the partnership agreement. You could, however, be liable for any and all of our obligations as if you were a general partner if:

§  
a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
§  
your right to act with other unitholders to take other actions under our partnership agreement is found to constitute “control” of our business.

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.  Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets.  Delaware law provides that for a period of three years from the date of the distribution, limited partners who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.  Substituted limited partners are liable for the obligations of the assignor to make required contributions to the partnership other than contribution obligations that are unknown to the substituted limited partner at the time it became a limited partner and that could not be ascertained from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

TAX RISKS RELATING TO OUR COMMON UNITS

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.

Under Section 7704 of the Internal Revenue Code, a publicly traded partnership will be taxed as a corporation unless it satisfies a “qualifying income” exception that allows it to be treated as a partnership for U.S. federal income tax purposes.  We believe that we meet the “qualifying income” exception and currently expect to meet such exception for the foreseeable future.  If the IRS were to disagree and 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.

26

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 been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships. Although such legislation would not apply to us as currently proposed, it could be amended prior to enactment in a manner that does apply to us.  We are unable to predict whether any of these changes or other proposals 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.

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.

We did not request a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us.  The IRS may adopt positions that differ from the positions we take.  It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take.  A court may 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.

You 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, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us.  You may not receive cash distributions from us equal to your 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 you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units.  Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost.  A substantial portion of the amount realized, whether or not representing gain, may be ordinary income.  In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

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

Investment in common units by tax-exempt entities, such as 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 you are a tax-exempt entity or a regulated investment company, you should consult your 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 you.  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 your tax returns.



27

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, and, accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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 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 intangible assets and a lesser portion allocated to our tangible 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.

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.  Pursuant to the GE EFS Acquisition, GE EFS acquired (i) a 37.3 percent limited partner interest in us, (ii) the 2 percent general partner interest in us, and (iii) the right to receive the incentive distributions associated with the general partner interest.  We believe, and will take the position, that the GE EFS Acquisition, together with all other common units sold within the prior twelve-month period, represented a sale or exchange of 50 percent or more of the total interest in our capital and profits interests.  This termination, among other things, resulted in the closing of our taxable year for all unitholders on June 18, 2007.  Such a closing of the books resulted in a significant deferral of depreciation deductions allowable in computing our taxable income.  Although our termination likely caused our unitholders to realize an increased amount of taxable income as a percentage of the cash distributed to them in 2007, 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 and Arkansas.  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.

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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 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.

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, except for those owned by one of our subsidiaries, by the Partnership and each such subsidiary.    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 one entire floor in an office building at 1700 Pacific Avenue, Dallas, Texas, under a lease that expires at the end of October 2008.  Currently, we are evaluating our executive office space needs. We also maintain small regional offices located on leased premises in Shreveport, Louisiana; and Midland, Houston, and San Antonio, Texas.  We lease the San Antonio office space from BBE, a related party.  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 coverage 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.  Submission of Matters to a Vote of Security Holders
None.

Part II

Item 5.  Market for Registrant's Common Equity Related Stockholder Matters and Purchase 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 NASDAQ under the symbol “RGNC.”  As of February 13, 2008, the number of holders of record of common units was 51, including Cede & Co., as nominee for Depository Trust Company, which held of record 29,296,713 common units.  Additionally, there were 35 unitholders of record of our subordinated units, one unitholder of record for our Class D common units and one unitholder of record for our Class E common units.  There is no established public trading market for our subordinated units, our Class D common units or our Class E common units.  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 NASDAQ, and the cash distributions declared per common unit.


                   
               
Cash Distributions
 
   
Price Ranges
         
Declared
 
   
High
   
Low
   
(per unit)
 
2006
                 
First Quarter (1)
  $ 22.10     $ 19.47     $ 0.2217  
Second Quarter
    23.00       21.30       0.3500  
Third Quarter (2)
    24.52       22.24       0.3700  
Fourth Quarter (2)
    27.20       24.75       0.3700  
2007
                       
First Quarter
    28.40       26.11       0.3800  
Second Quarter
    33.18       24.97       0.3800  
Third Quarter
    34.32       29.15       0.3900  
Fourth Quarter
    33.37       28.46       0.4000  
2008
                       
First Quarter (through February 21, 2008)
    32.60       29.71       (3 )
                         
(1) The distribution for the quarter ended March 31, 2006 reflects a pro rata portion of our $0.35 per unit minimum quarterly distribution,
 
covering the period from the February 3, 2006 closing of our initial public offering through March 31, 2006.
 
                         
(2) Excludes the Class B and Class C common units which were not entitled to any distributions until after they were converted into common
 
units. The Class B Units and the Class C Units converted into common units on a one-for-one basis on February 15, 2007 and February 8,
 
2007, respectively, and as such, are entitled to future cash distributions from the dates of conversion, respectively.
 
                         
(3) The cash distribution for the first quarter of 2008 will be determined in April 2008.
         

Cash Distribution Policy
We distribute to our unitholders, on a quarterly basis, all of our available cash in the manner described below.  During the subordination period (as defined in our partnership agreement), the common units will have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution, or MQD, of $0.35 per quarter, plus any arrearages in the payment of the MQD on the common units from prior quarters, before any distributions of available cash may be made on the subordinated units.  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 and subordinated units so that we may satisfy such obligations, including payments on our debt instruments.  Holders of our Class D common units and our Class E common units are not entitled to participate in distributions.

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.

In addition to distributions on its 2 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.

 
Total
         
 
Quarterly
 
Marginal Percentage
 
 
Distribution
 
Interest in Distributions
 
 
Target
     
General
 
 
Amount
 
Unitholders
 
Partner
 
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
 
15
 
Third Target Distribution
above $0.4375 up to $0.5250
 
75
 
25
 
Thereafter
above $0.5250
 
50
 
50
 

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.

30


Recent Sales of Unregistered Securities
On September 8, 2005, in connection with our formation we issued (i) to our general partner, Regency GP LP, its 2 percent general partner interest in us for $20 and (ii) to Regency Acquisition LLC its 98 percent limited partner interest in us for $980.  As an integral part of the reorganization of RGS in connection with our initial public offering, we issued (i) 5,353,896 common units and 19,103,896 subordinated units to Regency Acquisition LP, successor to Regency Acquisition LLC, in exchange for certain equity interests in RGS and its general partner and (ii) incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) to our general partner in exchange for certain member interests.

On August 15, 2006, in connection with the TexStar acquisition, we issued 5,173,189 of Class B common units to HMTF Gas Partners as partial consideration for the TexStar acquisition.  The Class B common units had the same terms and conditions as our common units, except that the Class B common units were not entitled to participate in distributions by the Partnership.  The Class B common units were converted into common units without the payment of further consideration on a one-for-one basis on February 15, 2007.  The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On September 21, 2006, we entered into a Class C Unit Purchase Agreement with certain purchasers, pursuant to which the purchasers purchased from us 2,857,143 Class C common units representing limited partner interests in the Partnership at a price of $21 per unit.  The Class C common units had the same terms and conditions as the Partnership’s common units, except that the Class C common units were not entitled to participate in distributions by the Partnership.  The Class C common units were converted into common units without the payment of further consideration on a one-for-one basis on February 8, 2007.  The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On April 2, 2007, in connection with the Pueblo Acquisition, we issued 751,597 common units to Bear Cub Investments, LLC and the members of that company as partial consideration for the Pueblo Acquisition.  The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On January 7, 2008, we issued 4,701,034 of Class E common units as partial consideration for the contribution of ASC’s 95 percent ownership interest in FrontStreet.  The Class E common units had the same terms and conditions as our common units, except that the Class E common units were not entitled to participate in distributions by the Partnership.  The Class E common units may be converted into an equivalent number of common units anytime from and after February 15, 2008.  The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

On January 15, 2008, we issued 7,276,506 of Class D common units to CDM OLP GP, LLC, the sole general partner of CDM, and CDMR Holdings, LLC, the sole limited partner of CDM, as partial consideration for the CDM Acquisition.  The Class D common units have the same terms and conditions as our common units, except that the Class D common units are not entitled to participate in distributions by the Partnership until converted to common units on a one-for-one basis on the close of business on the first business day after the record date for the quarterly distribution on the common units for the quarter ending December 31, 2008.  The registrant claims exemption from the registration provisions of the Securities Act of 1933 under section 4(2) thereof for these issuances.

There have been no other sales of unregistered equity securities during the last three years.

Item 6.  Selected Financial Data
The historical financial information presented below for the Partnership and our predecessors, Regency LLC Predecessor and Regency Gas Services LP (formerly Regency Gas Services LLC), was derived from our audited consolidated financial statements as of December 31, 2007, 2006, 2005, and 2004 and for the years ended December 31, 2007, 2006, and 2005, the one-month period ended December 31, 2004, the eleven-month period ended November 30, 2004, and the period from inception (April 2, 2003) to December 31, 2003.  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.

We refer to Regency Gas Services LLC as “Regency LLC Predecessor” for periods prior to its acquisition by the HM Capital Investors.



 
   
Regency Energy Partners LP
   
Regency LLC Predecessor
 
                     
Period from
         
Period from
 
                     
Acquisition
   
Period from
   
Inception
 
   
Year Ended
   
Year Ended
   
Year Ended
   
(December 1, 2004) to
   
January 1, 2004 to
   
(April 2, 2003) to
 
   
December 31, 2007
   
December 31, 2006
   
December 31, 2005
   
December 31, 2004
   
November 30, 2004
   
December 31, 2003
 
   
(in thousands except per unit data)
             
 Statement of Operations Data:
                                   
 Total revenue
  $ 1,168,054     $ 896,865     $ 709,401     $ 47,857     $ 432,321     $ 186,533  
 Total operating expense
    1,114,843       857,005       695,366       45,112       404,251       178,172  
 Operating income
    53,211       39,860       14,035       2,745       28,070       8,361  
 Other income and deductions
                                               
 Interest expense, net
    (52,016 )     (37,182 )     (17,880 )     (1,335 )     (5,097 )     (2,392 )
 Loss on debt refinancing
    (21,200 )     (10,761 )     (8,480 )     -       (3,022 )     -  
 Other income and deductions, net
    1,308       839       733       64       186       205  
 Net income (loss) from continuing operations
    (18,697 )     (7,244 )     (11,592 )     1,474       20,137       6,174  
 Discontinued operations
    -       -       732       -       (121 )     -  
 Income tax expense
    931       -       -       -       -       -  
 Net income (loss)
  $ (19,628 )   $ (7,244 )   $ (10,860 )   $ 1,474     $ 20,016     $ 6,174  
                                                 
Less:
                                               
Net income through January 31, 2006
    -       1,564                                  
Net loss for partners
  $ (19,628 )   $ (8,808 )                                
 General partner interest
    (393 )     (176 )                                
 Beneficial conversion feature for Class C common units
    1,385       3,587                                  
 Limited partner interest
  $ (20,620 )   $ (12,219 )                                
                                                 
Basic and diluted net loss per common and subordinated unit (1)
  $ (0.40 )   $ (0.30 )                                
Cash distributions declared per common and subordinated unit
    1.52       0.9417                                  
                                                 
Basic and diluted net loss per Class B common unit (1)
    -       (0.17 )                                
Cash distributions declared per Class B common unit
    -       -                                  
                                                 
Income per Class C common unit due to beneficial conversion feature (1)
    0.48       1.26                                  
Cash distributions declared per Class C common unit
    -       -                                  
                                                 
Balance Sheet Data (at period end):
                                         
 Property, plant and equipment, net
  $ 818,054     $ 734,034     $ 609,157     $ 328,784             $ 118,986  
 Total assets
    1,173,877       1,013,085       806,740       492,170               164,330  
 Long-term debt (long-term portion only)
    481,500       664,700       428,250       248,000               55,387  
 Net equity
    470,331       212,657       230,962       181,936               59,856  
 Cash Flow Data:
                                               
Net cash flows provided by (used in):
                                         
 Operating activities
  $ 74,413     $ 44,156     $ 37,340     $ (4,311 )   $ 32,401     $ 6,494  
 Investing activities
    (151,451 )     (223,650 )     (279,963 )     (130,478 )     (84,721 )     (123,165 )
 Financing activities
    95,721       184,947       242,949       132,515       56,380       118,245  
                                                 
 Other Financial Data:
                                               
 Total segment margin (2)
  $ 191,909     $ 156,419     $ 76,536     $ 6,870     $ 69,559     $ 23,072  
 EBITDA (2)
    85,058       69,592       30,191       4,470       35,242       12,890  
 Maintenance capital expenditures
    7,734       16,433       9,158       358       5,548       1,633  
                                                 
Segment Financial and Operating Data:
                                         
Gathering and Processing Segment:
                                         
 Financial data:
                                               
 Segment margin
  $ 132,577     $ 111,372     $ 60,864     $ 6,262     $ 61,347     $ 18,805  
 Operating expenses
    40,970       35,008       22,362       1,655       16,230       6,131  
 Operating data:
                                               
 Natural gas throughput (MMbtu/d)
    745,020       529,467       345,398       314,812       303,345       211,474  
 NGL gross production (Bbls/d)
    21,803       18,587       14,883       16,321       14,487       9,434  
 Transportation Segment:
                                               
 Financial data:
                                               
 Segment margin
  $ 59,332     $ 45,047     $ 15,672     $ 608     $ 8,212     $ 4,267  
 Operating expenses
    4,504       4,488       1,929       164       1,556       881  
 Operating data:
                                               
 Throughput (MMbtu/d)
    751,761       587,098       258,194       161,584       192,236       211,569  

(1) The year ended December 31, 2006 amounts have been corrected for an error made in the calculation of loss per unit resulting from the issuance of Class C common units at a discount.
(2) 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 and 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.  EBITDA is used as a supplemental 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.

EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

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EBITDA does 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, to evaluate our performance.

We define total segment margin as total revenues, including service fees, less cost of gas and liquids.  Total segment margin is included as a supplemental disclosure because it is a primary performance measure used by our management as it represents the results of product sales, service fee revenues and product purchases, a key component of our operations.  We believe total segment margin is an important measure because it is 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 revenues in calculating total segment margin because we separately evaluate commodity volume and price changes in total segment margin.  As an indicator of our operating performance, 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 may not be comparable to a similarly titled measure of another company because other entities may not calculate total segment margin in the same manner.

                                     
   
Regency Energy Partners LP
   
Regency LLC Predecessor
 
                     
Period from
         
Period from
 
                     
Acquisition Date
   
Period from
   
Inception
 
   
Year Ended
   
Year Ended
   
Year Ended
   
(December 1, 2004)
   
January 1, 2004 to
   
(April 2, 2003) to
 
   
December 31, 2007
   
December 31, 2006
   
December 31, 2005
   
to December 31, 2004
   
November 30, 2004
   
December 31, 2003
 
   
(in thousands)
             
Reconciliation of "EBITDA" to net cash flows provided by (used in) operating activities and to net (loss) income
             
Net cash flows provided by (used in) operating activities
  $ 74,413     $ 44,156     $ 37,340     $ (4,311 )   $ 32,401     $ 6,494  
Add (deduct):
                                               
Depreciation and amortization
    (53,734 )     (39,287 )     (24,286 )     (1,793 )     (10,461 )     (4,658 )
Write-off of debt issuance costs
    (5,078 )     (10,761 )     (8,480 )     -       (3,022 )     -  
Equity income
    43       532       312       56       -       -  
Risk management portfolio value changes
    (14,667 )     2,262       (11,191 )     322       -       -  
Loss (gain) on assets sales
    (1,522 )     -       1,254       -       -       -  
Unit based compensation expenses
    (15,534 )     (2,906 )     -       -       -       -  
Accrued revenues and accounts receivable
    30,608       5,506       43,012       (2,568 )     19,832       31,966  
Other current assets
    1,293       (104 )     2,644       2,456       1,169       1,070  
Accounts payable, accrued cost of gas and liquids and accrued liabilities
    (36,319 )     1,359       (52,651 )     (548 )     (18,122 )     (26,880 )
Accrued taxes payable
    (835 )     (492 )     (806 )     921       (1,475 )     (906 )
Other current liabilities
    984       (3,148 )     (1,269 )     242       (502 )     (917 )
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
    (358 )     (3,283 )     3,261       6,697       196       5  
Net (loss) income
  $ (19,628 )   $ (7,244 )   $ (10,860 )   $ 1,474     $ 20,016     $ 6,174  
  Add:
                                               
   Interest expense, net
    52,016       37,182       17,880       1,335       5,097       2,392  
   Depreciation and amortization
    51,739       39,654       23,171       1,661       10,129       4,324  
   Income tax expense     931                                
EBITDA
  $ 85,058     $ 69,592     $ 30,191     $ 4,470     $ 35,242     $ 12,890  
                                                 
Reconciliation of "total segment margin" to net (loss) income
                                         
Net (loss) income
  $ (19,628 )   $ (7,244 )   $ (10,860 )   $ 1,474     $ 20,016     $ 6,174  
Add (deduct):
                                               
Operation and maintenance
    45,474       39,496       24,291       1,819       17,786       7,012  
General and administrative
    39,543       22,826       15,039       645       6,571       2,651  
Loss on assets sales, net
    1,522       -       -       -       -       -  
Management services termination fee
    -       12,542       -       -       -       -  
Transaction expenses
    420       2,041       -       -       7,003       724  
Depreciation and amortization
    51,739       39,654       23,171       1,661       10,129       4,324  
Interest expense, net
    52,016       37,182       17,880       1,335       5,097       2,392  
Loss on debt refinancing
    21,200       10,761       8,480       -       3,022       -  
Other income and deductions, net
    (1,308 )     (839 )     (733 )     (64 )     (186 )     (205 )
Discontinued operations
    -       -       (732 )     -       121       -  
Income tax expense
    931       -       -       -       -       -  
Total segment margin
  $ 191,909     $         156,419     $ 76,536     $ 6,870     $ 69,559     $ 23,072  

 
 
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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 engaged in the gathering, processing, contract compression, marketing and transportation of natural gas and NGLs.  We provide these services through systems located in Louisiana, Texas, Arkansas, and the mid-continent region of the United States, which includes Kansas, Oklahoma, and Colorado.

OUR OPERATIONS. Prior to the acquisition of CDM in January 2008, we managed our business and analyzed and reported our results of operations through two 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 from the raw natural gas and selling or delivering the pipeline-quality natural gas and NGLs to various markets and pipeline systems; and

§  
Transportation:  We deliver natural gas from northwest Louisiana to more favorable markets in northeast Louisiana through our 320-mile Regency Intrastate Pipeline system.

On January 15, 2008, we acquired CDM, which now comprises our contract compression segment.  Our contract compression segment provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow.  Our integrated solutions include a comprehensive assessment of a customer’s natural gas contract compression needs and the design and installation of a compression system that addresses those particular needs.  We are responsible for the installation and ongoing operation, service, and repair of our compression units, which we modify as necessary to adapt to our customers’ changing operating conditions.

Through December 31, 2007, all of our revenue is derived from, and all of our assets and operations are part of our gathering and processing segment and our transportation segment.  As such the following discussion of our financial condition and results of operation does not reflect our contract compression segment.

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 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 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.  The following is a summary of our most common contractual arrangements:

§  
Fee-Based Arrangements.  Under these arrangements, we generally are 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 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) provisions that require the keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value than their thermal equivalent in natural gas, (2) 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, (3) fixed cash fees for ancillary services, such as gathering, treating, and compression, or (4) the ability to bypass processing in unfavorable price environments.

Percent-of-proceeds and keep-whole arrangements involve commodity price risk to us because our 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, crude oil, and natural gas market prices.  We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge position as conditions warrant.

Transportation segment. Results of operations from our Transportation segment are determined primarily by the volumes of natural gas transported on our Regency Intrastate Pipeline system and the level of fees charged to our customers or the margins received from purchases and sales of natural gas.  We generate revenues and segment margins for our Transportation segment principally under fee-based transportation contracts or through the purchase of natural gas at one of the inlets to the pipeline and the sale of natural gas at an outlet.  The margin we earn from our transportation activities is directly related to the volume of natural gas that flows through our system and is not directly dependent on commodity prices.  If a sustained decline in commodity prices should result in a decline in volumes, our revenues from these arrangements would be reduced.

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Generally, we provide to shippers two types of fee-based transportation services under our transportation contracts:

§  
Firm Transportation.  When we agree to provide firm transportation service, we become 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 our 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 us.
§  
Interruptible Transportation.  When we agree to provide interruptible transportation service, we become obligated to transport natural gas nominated by the shipper only to the extent that we have available capacity.  For this service the shipper pays no reservation charge but pays a commodity charge for quantities actually shipped.

We provide transportation services under the terms of our contracts and under an operating statement that we have filed and maintain with the FERC with respect to transportation authorized under section 311 of the NGPA.

In addition, we perform a limited merchant function on our Regency Intrastate Pipeline system.  This merchant function is conducted by a separate subsidiary.  We purchase natural gas from a producer or gas marketer at a receipt point on our system at a price adjusted to reflect our transportation fee and transport that gas to a delivery point on our 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 on the date of settlement.

We sell natural gas on intrastate and interstate pipelines to marketing affiliates of natural gas pipelines, marketing affiliates of integrated oil companies 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.

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 and operating and maintenance expenses on a segment basis and EBITDA on a 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 (1) the level of workovers or recompletions of existing connected wells and successful drilling activity in areas currently dedicated to our gathering and processing systems, (2) our ability to compete for volumes from successful new wells in other areas and (3) 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.

To increase throughput volumes on our intrastate pipeline we must contract with shippers, including producers and marketers, for supplies of natural gas.  We routinely monitor producer and marketing activities in the areas served by our transportation system in search of new supply opportunities.

Segment Margin.  We calculate our Gathering and Processing segment margin as our revenue generated from our gathering and processing operations minus the cost of natural gas and NGLs purchased and other cost of sales, including third-party transportation and processing fees.  Revenue includes revenue from the sale of natural gas and NGLs resulting from these activities and fixed fees associated with the gathering and processing of natural gas.

We calculate our Transportation segment margin as revenue generated by fee income as well as, in those instances in which we purchase and sell gas for our account, gas sales revenue minus the cost of natural gas that we purchase and transport.  Revenue primarily includes fees for the transportation of pipeline-quality natural gas and the margin generated by sales of natural gas transported for our account.  Most of our segment margin is fee-based with little or no commodity price risk.  We generally purchase pipeline-quality natural gas at a pipeline inlet price adjusted to reflect our transportation fee and we sell that gas at the pipeline outlet.  We regard the difference between the purchase price and the sale price as the economic equivalent of our transportation fee.

Total Segment Margin.  Segment margin from Gathering and Processing, together with segment margin from Transportation, comprise total segment margin.  We use total segment margin as a measure of performance.  See “Item 6 Selected Financial Data — Non-GAAP Financial Measures” for a reconciliation of this non-GAAP financial measure, total segment margin, to its most directly comparable GAAP measures, net cash flows provided by (used in) operating activities and net income (loss)