form10q.htm


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q
(Mark One)
þ
  
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934
   
For the quarterly period ended September 30, 2008
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
16-1731691
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
2001 BRYAN STREET, SUITE 3700
  
DALLAS, TX
75201
(Address of principal executive offices)
(Zip Code)
   
(214) 750-1771
 
(Registrant’s telephone number, including area code)
 
NONE
 
(Former name, former address and former fiscal year, if changed since last report.)
 
 

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.þ Yes o No

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 definition of “large accelerated filer, accelerated filer, and small reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
þ           Large accelerated filer                                           o Accelerated filer
o           Non-accelerated filer (Do not check if a smaller reporting company)    o           Smaller reporting company

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

The issuer had 54,815,951 common units, 7,276,506 Class D common units, and 19,103,896 subordinated units outstanding as of October 31, 2008.
 

 
 
 
 


 
Page
PART I — FINANCIAL INFORMATION
  4
  21
  35
  35
  35
PART II — OTHER INFORMATION
  35
  35
  36
  39
  39
  Exhibit 10-1  Employment Agreement with Randall Dean   
   
   
   
   
   

 
 
 
Introductory Statement
References in this report to the “Partnership,” “we,” “our,” “us” and similar terms, when used in a 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 quarterly report on Form 10-Q:
Name
Definition or Description
ASC
ASC Hugoton LLC, an affiliate of GECC
Bbls/d
Barrels per day
Bcf
One billion cubic feet
Bcf/d
One billion cubic feet per day
BTU
A unit of energy needed to raise the temperature of one pound of water by one degree Fahrenheit
CDM
CDM Resource Management LLC
CERCLA
Comprehensive Environmental Response, Compensation and Liability Act
DOT
U.S. Department of Transportation
EIA
Energy Information Administration
EnergyOne
FrontStreet EnergyOne LLC
El Paso
El Paso Field Services, LP
EPA
Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
FrontStreet
FrontStreet Hugoton LLC
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
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
Nexus
Nexus Gas Holdings, LLC
NOE
Notice of Enforcement
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
Partnership Agreement
Amended and Restated Agreement of Limited Partnership of Regency Energy Partners LP
 
1
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
SFAS
Statement of Financial Accounting Standard
Sonat
Southern Natural Gas Company
TCEQ
Texas Commission on Environmental Quality
Tcf
One trillion cubic feet
Tcf/d
One trillion cubic feet per day
TRRC
Texas Railroad Commission

 
2
 

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 and compression sectors of the natural gas industry;
· 
declines in the credit markets and the availability of credit for us as well as for producers connected to our systems and our customers;
· 
the level of creditworthiness of our counterparties and customers;
· 
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 operations of 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.  Many of the factors that will determine these results are beyond our ability to control or predict.  For additional discussion of risks, uncertainties and assumptions, see “Risk Factors” included in Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007 and in Part II, Item 1A of our quarterly reports on Form 10-Q.

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.

 
3
 
Part 1-Financial Information
Item 1. Financial Statements
Regency Energy Partners LP
  
Condensed Consolidated Balance Sheets
  
(in thousands except unit data)
  
             
   
September 30, 2008
    
December 31, 2007*
  
   
(Unaudited)
        
ASSETS
            
Current Assets:
            
     Cash and cash equivalents
   $ 14,819     $ 32,971  
     Restricted cash
     10,042       6,029  
     Trade accounts receivable, net of allowance of $870 in 2008 and $61 in 2007
     35,608       16,487  
     Accrued revenues
     131,058       117,622  
     Related party receivables
     1,508       61  
     Assets from risk management activities
     9,521       -  
     Other current assets
     6,685       6,723  
     Total current assets
     209,241       179,893  
                 
Property, plant and equipment
                
     Gathering and transmission systems
     616,187       635,206  
     Compression equipment
     754,710       145,555  
     Gas plants and buildings
     142,690       134,300  
     Other property, plant and equipment
     154,810       105,399  
     Construction-in-progress
     127,687       33,552  
Total property, plant and equipment
     1,796,084       1,054,012  
      Less accumulated depreciation
     (203,317 )     (140,903 )
Property, plant and equipment, net
     1,592,767       913,109  
                 
Other Assets:
                
     Intangible assets, net of accumulated amortization of $18,866 in 2008 and $8,929 in 2007
     205,447       77,804  
     Long-term assets from risk management activities
     14,424       -  
     Goodwill
     265,990       94,075  
     Other, net of accumulated amortization of debt issuance costs of $4,601 in 2008 and $2,488 in 2007
     16,974       13,529  
Total other assets
     502,835       185,408  
                 
TOTAL ASSETS
   $ 2,304,843     $ 1,278,410  
                 
LIABILITIES & PARTNERS' CAPITAL
                
Current Liabilities:
                
     Trade accounts payable
   $ 66,107     $ 48,904  
     Accrued cost of gas and liquids
     104,648       96,026  
     Related party payables
     -       50  
     Escrow payable
     10,042       6,029  
     Liabilities from risk management activities
     24,027       37,852  
     Other current liabilities
     31,845       9,397  
Total current liabilities
     236,669       198,258  
                 
Long-term liabilities from risk management activities
     6,170       15,073  
Other long-term liabilities
     15,591       15,393  
Long-term debt
     1,006,500       481,500  
Minority interest in consolidated subsidiary
     12,389       4,893  
                 
Commitments and contingencies
                
                 
Partners' Capital:
                
Common units (55,586,453 and 41,283,079 units authorized; 54,813,451 and 40,514,895 units issued and outstanding at September 30, 2008 and December 31, 2007)
     766,658       490,351  
Class D common units (7,276,506 units authorized, issued and outstanding at September 30, 2008)
     224,902       -  
Class E common units (4,701,034 units authorized, issued and outstanding at December 31, 2007)
     -       92,962  
Subordinated units (19,103,896 units authorized, issued and outstanding at September 30, 2008 and December 31, 2007)
     (609 )     7,019  
General partner interest
     29,232       11,286  
Accumulated other comprehensive income (loss)
     7,341       (38,325 )
Total partners' capital
     1,027,524       563,293  
                 
TOTAL LIABILITIES AND PARTNERS' CAPITAL
   $ 2,304,843     $ 1,278,410  
                 
See accompanying notes to condensed consolidated financial statements
  
                 
* Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.
                
                 

 
4
 
Regency Energy Partners LP
  
Condensed Consolidated Statements of Operations
  
Unaudited
  
(in thousands except unit data and per unit data)
  
                         
   
Three Months Ended
    
Nine Months Ended
  
   
September 30, 2008
    
September 30, 2007 *
    
September 30, 2008
    
September 30, 2007 *
  
                         
REVENUES
                        
Gas sales
   $ 323,411     $ 175,107     $ 922,872     $ 538,360  
NGL sales
     120,538       90,605       355,558       237,382  
Gathering, transportation and other fees, including related party amounts of $939, $541, $2,865 and $1,325
     74,267       30,478       206,429       69,553  
Net realized and unrealized gain (loss) from risk management activities
     6,817       (8,088 )     (39,600 )     (10,798 )
Other
     22,142       7,722       53,856       20,584  
    Total revenues
     547,175       295,824       1,499,115       855,081  
                                 
OPERATING COSTS AND EXPENSES
                                
Cost of sales, including related party amounts of $632, $656, $1,878 and $13,829
     408,165       234,946       1,168,441       696,644  
Operation and maintenance
     33,688       18,134       95,049       41,031  
General and administrative
     13,976       6,983       38,784       32,928  
(Gain) loss on asset sales, net
     (34 )     (777 )     434       1,562  
Management services termination fee
     -       -       3,888       -  
Transaction expenses
     2       -       536       -  
Depreciation and amortization
     26,422       14,993       74,638       39,123  
     Total operating costs and expenses
     482,219       274,279       1,381,770       811,288  
                                 
OPERATING INCOME
     64,956       21,545       117,345       43,793  
                                 
     Interest expense, net
     (16,072 )     (10,894 )     (48,261 )     (41,740 )
     Loss on debt refinancing
     -       (21,200 )     -       (21,200 )
     Other income and deductions, net
     118       713       450       951  
     Minority interest
     (162 )     (156 )     (165 )     (130 )
                                 
INCOME (LOSS) BEFORE INCOME TAXES
     48,840       (9,992 )     69,369       (18,326 )
                                 
     Income tax expense (benefit)
     (67 )     (160 )     142       65  
                                 
NET INCOME (LOSS)
   $ 48,907     $ (9,832 )   $ 69,227     $ (18,391 )
                                 
General partner's interest in current period net income (loss), including IDR
     7,592       (256 )     8,661       (433 )
Beneficial conversion feature for Class C common units
     -       -       -       1,385  
Beneficial conversion feature for Class D common units
     1,887       -       5,312       -  
Limited partners' interest in net income (loss)
   $ 39,428     $ (9,576 )   $ 55,254     $ (19,343 )
                                 
Basic and Diluted earnings per unit:
                                
Amount allocated to common and subordinated units
   $ 39,428     $ (12,540 )   $ 55,254     $ (22,621 )
Weighted average number of common and subordinated units outstanding
     70,043,532       55,269,457       63,838,515       48,306,666  
Basic income (loss) per common and subordinated unit
   $ 0.56     $ (0.23 )   $ 0.87     $ (0.47 )
Diluted income (loss) per common and subordinated unit
   $ 0.53     $ (0.23 )   $ 0.85     $ (0.47 )
Distributions per unit
   $ 0.445     $ 0.38     $ 1.265     $ 1.13  
                                 
Amount allocated to Class B common units
   $ -     $ -     $ -     $ -  
Weighted average number of Class B common units outstanding
     -       -       -       871,673  
Income per Class B common unit
   $ -     $ -     $ -     $ -  
Distributions per unit
   $ -     $ -     $ -     $ -  
                                 
Amount allocated to Class C common units
   $ -     $ -     $ -     $ 1,385  
Total number of Class C common units outstanding
     -       -       -       2,857,143  
Income per Class C common unit due to beneficial conversion feature
   $ -     $ -     $ -     $ 0.48  
Distributions per unit
   $ -     $ -     $ -     $ -  
                                 
Amount allocated to Class D common units
   $ 1,887     $ -     $ 5,312     $ -  
Total number of Class D common units outstanding
     7,276,506       -       7,276,506       -  
Income per Class D common unit due to beneficial conversion feature
   $ 0.26     $ -     $ 0.73     $ -  
Distributions per unit
   $ -     $ -     $ -     $ -  
                                 
Amount allocated to Class E common units
   $ -     $ 2,964     $ -     $ 3,278  
Total number of Class E common units outstanding
     -       4,701,034       4,701,034       4,701,034  
Income per Class E common unit
   $ -     $ 0.63     $ -     $ 0.70  
Distributions per unit
   $ -     $ 2.06     $ -     $ 2.32  
                                 
See accompanying notes to condensed consolidated financial statements
  
                                 
* Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.
                  

 
5
 

Regency Energy Partners LP
  
Condensed Consolidated Statements of Comprehensive Income (Loss)
  
Unaudited
  
(in thousands)
  
                         
   
Three Months Ended
    
Nine Months Ended
  
   
September 30, 2008
  
September 30, 2007 *
  
September 30, 2008
  
September 30, 2007 *
  
                         
Net income (loss)
   $ 48,907     $ (9,832 )   $ 69,227     $ (18,391 )
Net hedging amounts reclassified to earnings
     14,787       4,641       40,389       7,457  
Net change in fair value of cash flow hedges
     55,182       (11,694 )     5,277       (33,072 )
Comprehensive income (loss)
   $ 118,876     $ (16,885 )   $ 114,893     $ (44,006 )
                                 
See accompanying notes to condensed consolidated financial statements
  
                                 
* Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.
          

 
6
 

Regency Energy Partners LP
  
Condensed Consolidated Statements of Cash Flows
  
Unaudited
  
(in thousands)
  
             
   
Nine Months Ended
  
   
September 30, 2008
    
September 30, 2007 *
  
OPERATING ACTIVITIES
            
   Net income (loss)
   $ 69,227     $ (18,391 )
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
          
   Depreciation and amortization, including debt issuance cost amortization
     76,751       40,627  
   Write-off of debt issuance costs
     -       5,078  
   Equity income and minority interest in earnings
     165       130  
   Risk management portfolio valuation changes
     (1,007 )     1,634  
   Loss on asset sales
     434       1,562  
   Unit based compensation expenses
     3,087       14,790  
   Gain on insurance settlements
     (3,282 )     -  
   Cash flow changes in current assets and liabilities:
                
       Trade accounts receivable and accrued revenues
     (11,084 )     (14,857 )
       Other current assets
     38       251  
       Trade accounts payable, accrued cost of gas and liquids, and related party payables
     (11,125 )     15,171  
       Other current liabilities
     22,448       4,132  
 Other assets and liabilities
     3,628       (946 )
Net cash flows provided by operating activities
     149,280       49,181  
                 
INVESTING ACTIVITIES
                
  Capital expenditures
     (243,660 )     (108,983 )
  Acquisitions
     (577,344 )     (34,844 )
  Acquisition of investment in unconsolidated subsidiary, net of $100 cash
     -       (5,000 )
  Proceeds from asset sales
     696       11,723  
  Proceeds from insurance settlements
     3,282       -  
Net cash flows used in investing activities
     (817,026 )     (137,104 )
                 
FINANCING ACTIVITIES
                
   Net borrowings under revolving credit facilities
     525,000       33,300  
   Repayments under credit facilities
     -       (50,000 )
   Repayments of senior notes, net of debt issuance costs
     -       (192,500 )
   Partner contributions
     11,753       7,735  
   Partner distributions
     (86,448 )     (56,208 )
   Proceeds from option exercises
     2,700       -  
   Debt issuance costs
     (2,925 )     (1,164 )
   FrontStreet distributions
     -       (4,800 )
   FrontStreet contributions
     -       10,895  
   Proceeds from equity issuances, net of issuance costs
     199,514       353,446  
Net cash flows provided by financing activities
     649,594       100,704  
                 
Net increase (decrease) in cash and cash equivalents
     (18,152 )     12,781  
Cash and cash equivalents at beginning of period
     32,971       11,932  
Cash and cash equivalents at end of period
   $ 14,819     $ 24,713  
                 
Supplemental cash flow information:
                
   Interest paid, net of amounts capitalized
   $ 37,634     $ 51,324  
   Income taxes paid
     596       -  
   Non-cash capital expenditures in accounts payable
     24,871       3,359  
   Non-cash capital expenditures for consolidation of investment in previously unconsolidated subsidiary
     -       5,650  
   Non-cash capital expenditure upon entering into a capital lease obligation
     -       3,000  
   Issuance of common units for an acquisition
     219,590       19,724  
   Release of escrow payable from restricted cash
     4,487       -  
                 
See accompanying notes to condensed consolidated financial statements
  
                 
* Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.
          

 
7
 


Regency Energy Partners LP
  
Condensed Consolidated Statements of Partners' Capital
  
Unaudited
  
(in thousands except unit data)
  
                                                             
   
Units
                                          
   
Common
    
Class D
  
Class E
  
Subordinated
  
Common Unitholders
  
Class D Unitholders
  
Class E Unitholders
    
Subordinated Unitholders
    
General Partner Interest
    
Accumulated Other Comprehensive Income (Loss)
    
Total
  
Balance - December 31, 2007 *
     40,514,895       -     4,701,034     19,103,896   $ 490,351     $ -     $ 92,962     $ 7,019     $ 11,286     $ (38,325 )   $ 563,293  
Issuance of Class D common units
     -       7,276,506     -     -     -       219,590       -       -       -       -       219,590  
Issuance of restricted common units and option exercises, net of forfeitures
     576,613       -     -     -     2,700       -       -       -       -       -       2,700  
Issuance of common units
     9,020,909       -     -     -     199,514       -       -       -       -       -       199,514  
Working capital adjustment on FrontStreet
     -       -     -     -     -       -       (858 )     -       -       -       (858 )
Conversion of Class E common units
     4,701,034       -     (4,701,034 )   -     92,104       -       (92,104 )     -       -       -       -  
Unit based compensation expenses
     -       -     -     -     3,087       -       -       -       -       -       3,087  
General partner contributions
     -       -     -     -     -       -       -       -       11,753       -       11,753  
Partner distributions
     -       -     -     -     (59,814 )     -       -       (24,166 )     (2,468 )     -       (86,448 )
Net income
     -       -     -     -     38,716       5,312       -       16,538       8,661       -       69,227  
Net hedging amounts reclassified to earnings
     -       -     -     -     -       -       -       -       -       40,389       40,389  
Net change in fair value of cash flow hedges
     -       -     -     -     -       -       -       -       -       5,277       5,277  
Balance - September 30, 2008
     54,813,451       7,276,506     -     19,103,896   $ 766,658     $ 224,902     $ -     $ (609 )   $ 29,232     $ 7,341     $ 1,027,524  
                                                                                   
See accompanying notes to condensed consolidated financial statements
  
                                                                                   
*Recast to reflect an acquisition accounted for in a manner similar to a pooling of interests.
  

 
8
 
 
Regency Energy Partners LP
Notes to Unaudited Condensed Consolidated Financial Statements

1.  Organization and Summary of Significant Accounting Policies
Organization and Basis of Presentation. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP, a Delaware limited partnership, and its wholly owned and consolidated subsidiaries.  The Partnership and its subsidiaries are engaged in the business of gathering, processing, contract compression, marketing, and transporting natural gas and NGLs.  The Partnership operates and manages its business as three reportable segments: (a) gathering and processing, (b) transportation, and (c) contract compression.

On January 7, 2008, the Partnership acquired all of the outstanding equity and minority interest (the “FrontStreet Acquisition”) of FrontStreet from ASC and EnergyOne.  FrontStreet owns a gas gathering system located in Kansas and Oklahoma, which is operated by a third party.

The total purchase price consisted of (a) 4,701,034 Class E common units of the Partnership issued to ASC in exchange for its 95 percent interest and (b) $11,752,000 in cash to EnergyOne in exchange for its five percent minority interest and the termination of a management services contract valued at $3,888,000.  The Partnership financed the cash portion of the purchase price with borrowings under its revolving credit facility.

In connection with the FrontStreet Acquisition, the Partnership amended the Partnership Agreement to create the Class E common units.  The Class E common units have the same terms and conditions as the Partnership’s common units, except that the Class E common units are not entitled to participate in earnings or distributions of operating surplus by the Partnership.  The Class E common units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 as afforded by Section 4(2) thereof.  The Class E common units converted into common units on a one-for-one basis on May 5, 2008.

Because the acquisition of ASC’s 95 percent interest is a transaction between commonly controlled entities (i.e., the buyer and the seller were each affiliates of GECC), the Partnership accounted for this portion of the acquisition in a manner similar to the pooling of interest method.  Under this method of accounting, the financial statements reflected historical balance sheet data for both the Partnership and FrontStreet instead of reflecting the fair market value of FrontStreet’s assets and liabilities.  Further, certain transaction costs that would otherwise be capitalized were expensed. Common control between the Partnership and FrontStreet began on June 18, 2007.  Accordingly, the statement of operations for the three and nine months ending September 30, 2007 have been recast to include the results of FrontStreet from June 18, 2007 through the end of the period.

Conversely, the acquisition of the five percent minority interest is a transaction between independent parties, for which the Partnership applied the purchase method of accounting.  The final purchase price allocation, which management expects to be completed before year end, may differ from the estimates.

The following table summarizes the book values of the assets acquired and liabilities assumed at the date of common control, following the as-if pooled method of accounting.
 
       
   
At June 18, 2007
  
   
(in thousands)
  
       
Current assets
   $ 8,840  
Property, plant and equipment
     91,556  
Total assets acquired
     100,396  
Current liabilities
     (12,556 )
Net book value of assets acquired
   $ 87,840  
 
The unaudited financial information as of, and for the three and nine months ended, September 30, 2008 has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K, as amended by Form 8-K filed on May 9, 2008, for the year ended December 31, 2007.  In the opinion of the Partnership’s management, such financial information reflects all adjustments necessary for a fair presentation of the financial position and the results of operations for such interim periods in accordance with GAAP.  All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Use of Estimates. The unaudited condensed consolidated financial statements have been prepared in conformity with GAAP and, of necessity, include the use of estimates and assumptions by management.  Actual results could differ from these estimates.

9
Intangible Assets.  Intangible assets, net consist of the following.
 
   
Permits and Licenses
  
Customer Contracts
  
Trade Names
    
Total
  
   
(in thousands)
  
Balance at December 31,2007
   $ 9,368     $ 68,436     $ -     $ 77,804  
Additions
     -       102,480       35,100       137,580  
Disposals
     -       -       -       -  
Amortization
     (590 )     (7,680 )     (1,667 )     (9,937 )
Balance at September 30, 2008
   $ 8,778     $ 163,236     $ 33,433     $ 205,447  

The weighted average amortization period for permits and licenses, customer contracts, and trade names are 15, 20, and 15 years, respectively.  The expected amortization of the intangible assets for each of the five succeeding years is as follows.
 
Year ending December 31,
  
Total
  
   
(in thousands)
  
2008 (remaining)
   $ 3,456  
2009
     12,358  
2010
     12,264  
2011
     10,950  
2012
     10,713  

 
Recently Issued Accounting Standards.  In January 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of FASB Statement No. 115” (“SFAS No. 159”), which permits entities to measure many financial instruments and certain other assets and liabilities at fair value on an instrument-by-instrument basis. The adoption of SFAS No. 159 in 2008 had no impact on the Partnership’s financial position, results of operations or cash flows, as the Partnership has elected to continue valuing its outstanding senior notes at historical cost.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”), which significantly changes the accounting for business acquisitions both during the period of the acquisition and in subsequent periods.  SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008.  Generally, the effects of SFAS No. 141(R) will depend on future acquisitions.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51” (“SFAS No. 160”), which will significantly change the accounting and reporting related to noncontrolling interests in a consolidated subsidiary.  SFAS No. 160 is effective for fiscal years beginning after December 15, 2008.  The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows as a result of the adoption of this standard.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” (“SFAS No. 161”).  SFAS No. 161 requires enhanced disclosures about derivative and hedging activities.  These enhanced disclosures will address (a) how and why a company uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under FASB Statement No. 133 and its related interpretations and (c) how derivative instruments and related hedged items affect a company’s financial position, results of operations and cash flows.  SFAS No. 161 is effective for fiscal years and interim periods beginning on or after November 15, 2008, with earlier adoption allowed.  The Partnership is currently evaluating the potential impacts on its financial position, results of operations or cash flows of the adoption of this standard.

In March 2008, the FASB issued EITF 07-4, “Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships” (“EITF No. 07-4”).  EITF No. 07-4 defines how to allocate net income among the various classes of equity, including incentive distribution rights, narrowing the number of currently acceptable methods.  The standard becomes effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years.  Earlier application is not permitted, and EITF No. 07-4 must be applied retrospectively for all financial statements presented.  This new standard is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

10
In April 2008, FASB issued FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (“FSP No. 142-3”), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of intangible assets.  The objective of FSP No. 142-3 is to better match the useful life of intangible assets to the cash flow generated.  FSP No. 142-3 is effective for financial statements issued for fiscal years beginning after December 15, 2008 and interim periods within those fiscal years.  Early adoption of this statement is not permitted.  The Partnership is currently evaluating the potential impact of this standard on its financial position, results of operations and cash flows.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”), which identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements that are presented in conformity of GAAP.  SFAS No. 162’s effective date is November 15, 2008.  The adoption of SFAS No. 162 is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

In June 2008, the FASB issued FSP EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”).  Based on this guidance, the Partnership will include non-vested units granted under its LTIP in the basic earnings per unit calculation.  FSP EITF 03-6-1 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those years.  All prior-period earnings per unit data will be adjusted.  Early application is not permitted.  This new standard is not expected to have a material impact on the Partnership’s financial position, results of operations or cash flows.

2.  Income (Loss) per Limited Partner Unit
In connection with the CDM acquisition discussed below, the Partnership issued 7,276,506 Class D common units.  At the commitment date, the sales price of $30.18 per unit represented a $1.10 discount from the fair value of the Partnership’s common units.  Under EITF No. 98-5, “Accounting for Convertible Securities with Beneficial Conversion Features or Contingently Adjustable Conversion Ratios,” the discount represented a beneficial conversion feature that is treated as a non-cash distribution for purposes of calculating earnings per unit.  The beneficial conversion feature is reflected in income per unit using the effective yield method over the period the Class D common units are outstanding, as indicated on the statements of operations in the line item entitled “beneficial conversion feature for Class D common units.”

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per unit computations for the three and nine months ended September 30, 2008.

   
For the Three Months Ended September 30, 2008
    
For the Nine Months Ended September 30, 2008
  
   
Income (Numerator)
    
Units (Denominator)
    
Per-Unit Amount
    
Income (Numerator)
    
Units (Denominator)
    
Per-Unit Amount
  
   
(in thousands except unit and per unit data)
  
Basic Earnings per Unit
                                    
Limited partner's interest in net income
   $ 39,428       70,043,532     $ 0.56     $ 55,254       63,838,515     $ 0.87  
Effect of Dilutive Securities
                                                
Common unit options
     -       37,969               -       111,134          
Restricted common units
     -       18,412               -       50,657          
Class D common units
     1,887       7,276,506               5,312       7,276,506          
Diluted Earnings per Unit
   $ 41,315       77,376,419     $ 0.53     $ 60,566       71,276,812     $ 0.85  
 
The following data show securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted EPS because to do so would have been antidilutive for the periods presented.
 

   
Three Months Ended
    
Nine Months Ended
  
   
September 30, 2008
    
September 30, 2007
    
September 30, 2008
    
September 30, 2007
  
Restricted common units
     -       386,500       -       386,500  
Common unit options
     -       776,968       -       776,968  
 
 
3.  Acquisitions and Dispositions
CDM Resource Management, Ltd. On January 15, 2008, the Partnership and an indirect wholly owned subsidiary of the Partnership (“Merger Sub”) consummated an agreement and plan of merger (the “Merger Agreement”) with CDM Resource Management, Ltd.  CDM provides its 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.  The Partnership operates and manages CDM as a separate reportable segment.

11
The total purchase price paid by the Partnership for the partnership interests of CDM consisted of (a) the issuance of an aggregate of 7,276,506 Class D common units of the Partnership, which were valued at $219,590,000 and (b) an aggregate of $478,445,000 in cash, $316,500,000 of which was used to retire CDM’s debt obligations.  Of the Class D common units issued, 4,197,303 Class D common units were deposited with an escrow agent pursuant to an escrow agreement.  Such common units constitute security to the Partnership for a period of one year after the closing with respect to any obligations under the Merger Agreement, including obligations for breaches of representation, warranties and covenants.

In connection with the CDM merger, the Partnership amended the Partnership Agreement to create the Class D common units.  The Class D common units have the same terms and conditions as the Partnership’s common units, except that the Class D common units are not entitled to participate in distributions of operating surplus by the Partnership.  The Class D common units automatically convert into 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 Class D common units were issued in a private placement conducted in accordance with the exemption from the registration requirements of the Securities Act of 1933 under Section 4(2) thereof.

The total purchase price of $699,702,000, including direct transaction costs, was allocated preliminarily as follows.

   
At January 15, 2008
  
   
(in thousands)
  
       
Current assets
   $ 19,463  
Other assets
     4,547  
Gas plants and buildings
     1,528  
Gathering and transmission systems
     421,160  
Other property, plant and equipment
     2,728  
Construction-in-progress
     36,239  
Identifiable intangible assets
     80,480  
Goodwill
     164,668  
Assets acquired
     730,813  
Current liabilities
     (31,054 )
Other liabilities
     (57 )
Net assets acquired
   $ 699,702  

The final purchase price allocation, which management expects to be completed before year end, may differ from the above estimates.

Nexus Gas Holdings, LLC. On March 25, 2008, the Partnership acquired Nexus (“Nexus Acquisition”) by merger for $88,486,000 in cash, including customary closing adjustments. Nexus Gas Partners LLC, the sole member of Nexus prior to the merger (“Nexus Member”), deposited $8,500,000 in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustment.  The Partnership funded the Nexus Acquisition through borrowings under its revolving credit facility.

Upon consummation of the Nexus Acquisition, the Partnership acquired Nexus’ rights under a Purchase and Sale Agreement (the “Sonat Agreement”) between Nexus and Sonat.  Pursuant to the Sonat Agreement, Nexus will purchase 136 miles of pipeline from Sonat (the “Sonat Asset Acquisition”) that could facilitate the Nexus gathering system’s integration into the Partnership’s north Louisiana asset base. The Sonat Asset Acquisition is subject to abandonment approval and jurisdictional redetermination by the FERC, as well as customary closing conditions.  Upon closing of the Sonat Asset Acquisition, the Partnership will pay Sonat $27,500,000, and, if the closing occurs on or prior to March 1, 2010, on certain terms and conditions as provided in the Merger Agreement, the Partnership will make an additional payment of $25,000,000 to the Nexus Member.

12
The total purchase price of $88,486,000 was allocated preliminarily as follows.

   
At March 25, 2008
  
   
(in thousands)
  
       
Current assets
   $ 3,457  
Buildings
     13  
Gathering and transmission systems
     16,960  
Other property, plant and equipment
     4,440  
Identifiable intangible assets
     57,100  
Goodwill
     7,187  
Assets acquired
     89,157  
Current liabilities
     (671 )
Net assets acquired
   $ 88,486  

The final purchase price allocation, which management expects to be completed before year end, may differ from the above estimates.

The following unaudited pro forma financial information has been prepared as if the acquisitions of FrontStreet, CDM and Nexus had occurred as of the beginning of the periods presented.  Results for the nine months ended September 30, 2007 include the Partnership’s acquisition of Pueblo because that acquisition occurred in April 2007.  Such unaudited pro forma financial information does not purport to be indicative of the results of operations that would have been achieved if the transactions to which the Partnership is giving pro forma effect actually occurred on the date referred to above or the results of operations that may be expected in the future.
 

 
   
Pro Forma Results for the
  
   
Three Months Ended
    
Nine Months Ended
  
   
September 30, 2008
    
September 30, 2007
    
September 30, 2008
    
September 30, 2007
  
   
(in thousands except unit and per unit data)
  
Revenue
   $ 547,175     $ 322,915     $ 1,506,322     $ 953,445  
                                 
Net income (loss)
   $ 48,907     $ (7,917 )   $ 71,041     $ (9,075 )
Less:
                                
  General partner's interest in current period net income (loss), including IDR
     7,592       (217 )     8,697       (246 )
  Beneficial conversion feature for Class C common units
     -       -       -       1,385  
  Beneficial conversion feature for Class D common units
     1,887       -       5,312       -  
Limited partners' interest in net income (loss)
   $ 39,428     $ (7,700 )   $ 57,032     $ (10,214 )
                                 
Basic and Diluted earnings per unit:
                                
Amount allocated to common and subordinated units
   $ 39,428     $ (10,664 )   $ 57,032     $ (13,492 )
Weighted average number of common and subordinated units outstanding
     70,043,532       55,269,457       63,838,515       48,306,666  
Basic income (loss) per common and subordinated unit
   $ 0.56     $ (0.19 )   $ 0.89     $ (0.28 )
Diluted income (loss) per common and subordinated unit
   $ 0.53     $ (0.19 )   $ 0.87     $ (0.28 )
Distributions per unit
   $ 0.445     $ 0.38     $ 1.265     $ 1.13  
                                 
Amount allocated to Class B common units
   $ -     $ -     $ -     $ -  
Weighted average number of Class B common units outstanding
     -       -       -       871,673  
Income per Class B common unit
   $ -     $ -     $ -     $ -  
Distributions per unit
   $ -     $ -     $ -     $ -  
                                 
Amount allocated to Class C common units
   $ -     $ -     $ -     $ 1,385  
Total number of Class C common units outstanding
     -       -       -       2,857,143  
Income per Class C common unit due to beneficial conversion feature
   $ -     $ -     $ -     $ 0.48  
Distributions per unit
   $ -     $ -     $ -     $ -  
                                 
Amount allocated to Class D common units
   $ 1,887     $ -     $ 5,312     $ -  
Total number of Class D common units outstanding
     7,276,506       -       7,276,506       -  
Income per Class D common unit due to beneficial conversion feature
   $ 0.26     $ -     $ 0.73     $ -  
Distributions per unit
   $ -     $ -             $ -  
                                 
Amount allocated to Class E common units
   $ -     $ 2,964     $ -     $ 3,278  
Total number of Class E common units outstanding
     -       4,701,034       4,701,034       4,701,034  
Income per Class E common unit
   $ -     $ 0.63     $ -     $ 0.70  
Distributions per unit
   $ -     $ 2.06             $ 2.32  
 
13
4.  Risk Management Activities
The net fair value of the Partnership’s risk management activities constituted a net liability of $6,252,000 at September 30, 2008.  The Partnership expects to reclassify $963,000 of net hedging gains to revenues or interest expense from accumulated other comprehensive income (loss) in the next twelve months.  During the three and nine months ended September 30, 2008, the Partnership recorded $19,917,000 and $2,090,000 of mark-to-market gain and loss, respectively, for certain commodity hedges that do not qualify for hedge accounting.  In the three and nine months ended September 30, 2008, the Partnership recognized $1,512,000 and $1,998,000 of ineffectiveness gains, respectively. In the three and nine months ended September 30, 2008, the Partnership recorded in net realized and unrealized gain (loss) from risk management activities a $162,000 and $1,110,000, respectively, of gains associated with its credit risk assessment in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”).
 
The Partnership’s hedging positions help reduce exposure to variability of future commodity prices through 2010 and future interest rates on $300,000,000 of long-term debt under its revolving credit facility through March 5, 2010, the date the interest rate swaps expire.
 
Effective June 19, 2007, the Partnership elected to account for all outstanding commodity hedging instruments on a mark-to-market basis except for the portion pursuant to which all NGL products for a particular year were hedged and the hedging relationship was, for accounting purposes, effective.  The Partnership has a total of six hedging programs for a three-year period including 2008 through 2010 NGL hedging programs and West Texas Intermediate crude oil hedging programs to hedge condensate for 2008 through 2010.
 
In March 2008, the Partnership entered offsetting trades against its existing 2009 portfolio of mark-to-market hedges, which it believes will substantially reduce the volatility of its 2009 hedges.  This group of trades, along with the pre-existing 2009 portfolio, will continue to be accounted for on a mark-to-market basis.  Simultaneously, the Partnership executed additional 2009 NGL swaps which were designated under SFAS No. 133 as cash flow hedges. In May 2008, the Partnership entered into commodity swaps to hedge a portion of its 2010 NGL commodity risk, except for ethane, which are accounted for using mark-to-market accounting.
 
The Partnership accounts for a portion of its 2008 and, prior to August 2008, accounted for all of its 2009 West Texas Intermediate crude oil swaps using mark-to-market accounting.  In August 2008, the Partnership entered into an offsetting trade against its existing 2009 West Texas Intermediate crude oil swap to minimize the volatility of the original 2009 swap.  Simultaneously, the Partnership executed an additional 2009 West Texas Intermediate crude oil swap, which was designated under SFAS No. 133 as a cash flow hedge.  In May 2008, the Partnership entered into West Texas Intermediate crude oil swap to hedge its 2010 condensate price risk, which was designated as a cash flow hedge in June 2008.
 
On February 29, 2008, the Partnership entered into two-year interest rate swaps related to $300,000,000 of borrowings under its revolving credit facility, effectively locking the base rate for these borrowings at 2.4 percent, plus the applicable margin (2.0 percent as of September 30, 2008) through March 5, 2010. These interest rate swaps were designated as cash flow hedges in March 2008.

5.  Long-Term Debt
Long-term debt obligations of the Partnership are as follows:

             
   
September 30, 2008
    
December 31, 2007
  
   
(in thousands)
  
             
 Senior notes
   $ 357,500     $ 357,500  
 Revolving loans
     649,000       124,000  
 Total
     1,006,500       481,500  
 Less: current portion
     -       -  
 Long-term debt
   $ 1,006,500     $ 481,500  
                 
 Availability under revolving credit facility:
                
 Total credit facility limit
   $ 900,000     $ 500,000  
 Revolving loans
     (649,000 )     (124,000 )
 Letters of credit
     (16,257 )     (27,263 )
 Total available
   $ 234,743     $ 348,737  

14
RGS entered into Amendment No. 4 to its Fourth Amended and Restated Credit Facility on January 15, 2008, thereby expanding its revolving credit facility to $750,000,000.  RGS also entered into Amendment No. 5 to its Fourth Amended and Restated Credit Facility on February 13, 2008, expanding its revolving credit facility to $900,000,000 and availability for letters of credit to $100,000,000.  The Partnership has the option to request an additional $250,000,000 in revolving and/or term loan commitments with ten business days written notice provided that no event of default has occurred or would result due to such increase, and all other additional conditions for the increase of the commitments set forth in the credit facility have been met.  These amendments did not materially change other terms of the RGS revolving credit facility.

On September 15, 2008, Lehman Brothers Holdings, Inc. (“Lehman”) filed a petition in the United States Bankruptcy Court seeking relief under chapter 11 of the United States Bankruptcy Code.  Of the amount committed by Lehman, the Partnership has borrowed all but $9,129,000.  Lehman has declined requests to honor its remaining commitment, effectively reducing the total size of the Fourth Amended and Restated Credit Facility capacity to $890,871,000. If we repay any of the $25,871,000 we have already borrowed from Lehman, we will not be able to reborrow such amounts unless another lender assumes Lehman's commitment.
 
The outstanding balance of revolving debt under the credit facility bears interest at LIBOR plus a margin or Alternative Base Rate (equivalent to the U.S. prime lending rate) plus a margin, or a combination of both. The weighted average interest rates for the revolving loans and senior notes, including interest rate swap settlements, commitment fees, and amortization of debt issuance costs were 6.37 percent and 8.74 percent for the nine months ended September 30, 2008 and 2007, respectively and 6.15 percent and 8.80 percent for the three months ended September 30, 2008 and 2007, respectively. The senior notes bear interest at a fixed rate of 8.375 percent. The estimated fair market value of the senior notes was $321,750,000 and $272,594,000 as of September 30, 2008 and November 6, 2008, respectively.

The senior notes are guaranteed by the Partnership’s subsidiaries (the “Guarantors”) on December 12, 2006, the date the notes were issued. These note guarantees are the joint and several obligations of the Guarantors.  A guarantor may not sell or otherwise dispose of all or substantially all of its properties or assets if such sale would cause a default under the terms of the senior notes. Events of default include nonpayment of principal or interest when due; failure to comply with certain limits on the payment of distributions; failure to make a change of control offer; failure to comply with reporting requirements according to SEC rules and regulations; and defaults on the payment of obligations under other indebtedness of $20,000,000 or more. Since certain subsidiaries do not guarantee the senior notes, the condensed consolidating financial statements of the guarantors and non-guarantors as of and for the nine months ended September 30, 2008 are disclosed below.

Condensed Consolidating Balance Sheets
  
September 30, 2008
  
Unaudited
  
   
Guarantors
    
Non Guarantors
    
Elimination
    
Consolidated
  
ASSETS
  
(in thousands)
  
Total current assets
   $ 191,412     $ 17,829     $ -     $ 209,241  
Property, plant and equipment, net
     1,500,197       92,570       -       1,592,767  
Total other assets
     502,835       -       -       502,835  
TOTAL ASSETS
   $ 2,194,444     $ 110,399     $ -     $ 2,304,843  
                                 
LIABILITIES & PARTNERS' CAPITAL
                                
Total current liabilities
   $ 232,502     $ 4,167     $ -     $ 236,669  
Long-term liabilities from risk management activities
     6,170       -       -       6,170  
Other long-term liabilities
     15,591       -       -       15,591  
Long-term debt
     1,006,500       -       -       1,006,500  
Minority interest
     12,389       -       -       12,389  
Partners' capital
     921,292       106,232       -       1,027,524  
TOTAL LIABILITIES & PARTNERS' CAPITAL
   $ 2,194,444     $ 110,399     $ -     $ 2,304,843  
                                 


Condensed Consolidating Statements of Operations
  
For the Nine Months Ended September 30, 2008
  
Unaudited
  
   
Guarantors
    
Non Guarantors
    
Elimination
    
Consolidated
  
   
(in thousands)
  
Total revenues
   $ 1,465,086     $ 34,029     $ -     $ 1,499,115  
Total operating costs and expenses
     1,353,211       28,559       -       1,381,770  
OPERATING INCOME
     111,875       5,470       -       117,345  
Interest expense, net
     (48,261 )     -       -       (48,261 )
Other income and deductions, net
     514       (64 )     -       450  
Minority interest
     (165 )     -       -       (165 )
INCOME BEFORE INCOME TAXES
     63,963       5,406       -       69,369  
Income tax expense
     142       -       -       142  
NET INCOME
   $ 63,821     $ 5,406     $ -     $ 69,227  
 

 
15
 

Condensed Consolidating Statements of Cash Flow
  
For the Nine Months Ended September 30, 2008
  
Unaudited
  
   
Guarantors
    
Non Guarantors
    
Elimination
    
Consolidated
  
   
(in thousands)
  
Net cash flows provided by (used in) operating activities
   $ 151,061     $ (1,781 )   $ -     $ 149,280  
Net cash flows used in investing activities
     (813,658 )     (3,368 )     -       (817,026 )
Net cash flows provided by financing activities
     649,594       -       -       649,594  
 
 
6.  Equity Offering
On August 1, 2008, the Partnership sold 9,020,909 common units for an average price of $22.18 per unit under the Partnership’s universal shelf registration statement.  The Partnership received $204,133,000 in proceeds, inclusive of the General Partner’s proportionate capital contribution of $4,082,653.  The net proceeds were used to repay indebtedness under the Partnership’s revolving credit facility.  An affiliate of GECC purchased 2,272,727 of these common units.  As of September 30, 2008, the Partnership has incurred $34,000 in costs related to this equity offering.

7.  Commitments and Contingencies
Legal. The Partnership is involved in various claims and lawsuits incidental to its business.  In the opinion of management, these claims and lawsuits in the aggregate will not have a material adverse effect on the Partnership’s business, financial condition, results of operations or cash flows.

Contingent Purchase of Sonat Assets. In March of 2008, the Partnership, through the Nexus Acquisition, obtained the rights to a contingent commitment to purchase 136 miles of pipeline that could facilitate the Nexus gathering system’s integration into the Partnership’s north Louisiana asset base. The purchase commitment is contingent upon the FERC declaring that the pipeline is no longer subject to its jurisdiction, together with approval of the current owner’s abandonment and other customary closing conditions.  In the event that all contingencies are satisfactorily resolved, the Partnership will pay Sonat $27,500,000.  Furthermore, if the closing occurs on or prior to March 1, 2010, the Partnership will pay an additional $25,000,000 to the sellers, subject to certain terms and conditions.

On April 3, 2008, Sonat filed an application with the FERC seeking authorization to abandon by sale to Nexus 136 miles of pipeline and related facilities.  The application also requested a determination that the facilities being sold to Nexus be considered non-jurisdictional, with certain facilities being gathering and certain facilities being intrastate transmission.  Four producers submitted letters in support of the application and several Sonat shippers protested the application.  The matter is currently pending.

Escrow Payable.  At September 30, 2008, $1,507,000 remained in escrow pending the completion by El Paso of environmental remediation projects pursuant to the purchase and sale agreement (“El Paso PSA”) related to assets in north Louisiana and the mid-continent area.  In the El Paso PSA, El Paso indemnified the predecessor of our operating partnership, RGS, against losses arising from pre-closing and known environmental liabilities subject to a limit of $84,000,000 and certain deductible limits.  Upon completion of a Phase II environmental study, the Partnership notified El Paso of remediation obligations amounting to $1,800,000 with respect to known environmental matters and $3,600,000 with respect to pre-closing environmental liabilities.

In January 2008, pursuant to authorization by the Board of Directors of the General Partner, the Partnership agreed to settle 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 Partnership-owned facilities.  El Paso is not obligated to clean up properties leased by the Partnership, but it indemnified the Partnership for pre-closing environmental liabilities.  All sites for which the Partnership made environmental claims against El Paso are either addressed in the settlement or have already been resolved.  In May 2008, the Partnership released all but $1,500,000 from the escrow fund maintained to secure El Paso’s obligations.  This amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion.

Nexus Escrow. At September 30, 2008, $8,535,000 is included in an escrow account as security to the Partnership for a period of one year against indemnification obligations and any purchase price adjustments related to the Nexus Acquisition.

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

16
TCEQ Notice of Enforcement. On February 15, 2008, the TCEQ issued a NOE concerning one of the Partnership’s processing plants located in McMullen County, Texas (the “Plant”).  The NOE alleges that, between March 9, 2006, and May 8, 2007, the Plant experienced 15 emission events of various durations from four hours to 41 days, which were not reported to TCEQ and other agencies within 24 hours of occurrence.  On April 3, 2008, TCEQ presented the Partnership with a written offer to settle the allegation in the NOE in exchange for payment of an administrative penalty of $480,000.  The Partnership was unable to settle this matter on a satisfactory basis and the TCEQ has referred the matter for further proceedings.

RIGS FERC Petition.  On April 29, 2008, RIGS filed a petition with the FERC seeking approval to maintain its maximum Section 311 transportation rates for firm and interruptible services as follows:  Firm Service – reservation fee of $4.5625 per MMBtu monthly ($0.15 per MMBtu daily) and commodity fee of $0.05 per MMBtu; Interruptible Service – transportation fee of $0.20 per MMBtu; and Fuel Retention - up to two percent of receipts.  The rate filing was required by a FERC Letter Order issued on September 26, 2005, which approved a settlement in which RIGS agreed to justify its existing rates or establish new rates for Section 311 services by May 1, 2008.

RIGS reached a settlement with FERC Staff on the 2008 petition, and on September 23, 2008, the FERC approved the settlement.  The settlement provided for the continuation of RIGS existing maximum transportation rates and a reduction in RIGS’ maximum fuel retention to one and a one-half percent effective May 1, 2008.  The settlement permits RIGS’ maximum fuel retention rate to increase to two percent when new compression is added to the RIGS system.   As part of the settlement, RIGS also agreed to fully support its requested maximum fuel retention percentage in its next rate filing and to re-justify or establish new rates for Section 311 service by May 1, 2011.  The triennial rate review requirement is a standard settlement provision in most intrastate pipeline rate proceedings for Section 311 service.

Keyes Litigation.  In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, and the General Partner.  Keyes entered into an output contract with the Partnership’s predecessor in 1996 under which it purchased all of the helium produced at the Lakin processing plant in southwest Kansas.  In September 2004, the Partnership decided to shut down the Lakin plant and contract with a third party for the processing of volumes processed at Lakin, as a result of which the Partnership no longer delivered any helium to Keyes.  As a result, Keyes alleges it is entitled to an unspecified amount of damages for the costs of covering its purchases of helium.  The Partnership filed an answer to this lawsuit and plans to defend itself vigorously.

Kansas State Severance Tax.  In August 2008, a customer began remitting severance tax to the state of Kansas based on the value of condensate purchased from one of the Partnership’s Mid-Continent gathering fields and deducting the tax from its payments to the Partnership.  The Kansas Department of Revenue advised the customer that it was appropriate to remit such taxes and withhold the taxes from its payments to the Partnership, absent an order or legal opinion from the Kansas Department of Revenue stating otherwise.  The Partnership has requested a determination from the Kansas Department of Revenue regarding the matter since severance taxes were already paid on the gas from which the condensate is collected and no additional tax is due.  If the Kansas Department of Revenue determines that the condensate sales are taxable, then the Partnership may be subject to additional taxes for past and future condensate sales.

Purchase Commitments.  At September 30, 2008, the Partnership has purchase obligations totaling $428,454,000, of which $148,924,000 relate to the purchase of major compression components unrelated to the expansion of RIGS, referred to in this document as the Haynesville Expansion Project, that extend until the year ending December 31, 2010 and $279,530,000 of commitments related to the Haynesville Expansion Project that extend until the year ending December 31, 2009. Some of these commitments have cancellation provisions. 

8.  Related Party Transactions
The employees operating the assets of the Partnership and its subsidiaries and substantially all those providing staff and support services are employees of the General Partner and other affiliates of the Partnership.  Pursuant to the Partnership Agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses that it incurs on behalf of the Partnership. Reimbursements of $7,284,000 and $7,169,000 were recorded in the Partnership’s financial statements during the three months ended September 30, 2008 and 2007, respectively, and reimbursements of $22,605,000 and $20,408,000 were recorded in the Partnership’s financial statements during the nine months ended September 30, 2008 and 2007, respectively, as operating expenses or general and administrative expenses, as appropriate.

17
In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS and affiliates received cash distributions of $25,396,000 and $7,212,000 during the nine months ended September 30, 2008 and 2007, respectively, as result of their ownership interests in the Partnership.

In conjunction with distributions by the Partnership to its limited and general partner interests, HM Capital Partners and affiliates received cash distributions of $10,308,000 and $21,215,000 during the nine months ended September 30, 2008 and 2007, respectively, as a result of their ownership interests in the Partnership.  In September 2008, HM Capital Partners and affiliates sold 7,100,000 common units, reducing their ownership percentage to an amount less than ten percent of the Partnership’s outstanding common units. As a result of this sale, HM Capital Partners is no longer a related party of the Partnership.

In conjunction with distributions by the Partnership to its limited and general partner interests, certain members of management received cash distributions of $1,382,000 in the nine months ended September 30, 2008 as a result of their ownership interests in the Partnership.

9.  Segment Information
The Partnership has three reportable segments: (a) gathering and processing, (b) transportation, and (c) contract compression.  Gathering and processing involves collecting raw natural gas from producer wells and transporting it to treating plants where water and other impurities such as hydrogen sulfide and carbon dioxide are removed. Treated gas is then processed to remove the natural gas liquids. The treated and processed natural gas is then transported to market separately from the natural gas liquids. Revenues and the associated cost of sales from the gathering and processing segment directly expose the Partnership to commodity price risk, which is managed through derivative contracts and other measures. The Partnership aggregates the results of its gathering and processing activities across five geographic regions into a single reporting segment.

The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with larger pipelines or trading hubs and other markets. The Partnership performs transportation services for shipping customers under firm or interruptible arrangements. In either case, revenues are primarily fee based and involve minimal direct exposure to commodity price fluctuations. The Partnership also purchases natural gas at the inlets to the pipeline and sells this gas at its outlets. The north Louisiana intrastate pipeline operated by this segment serves the Partnership’s gathering and processing facilities in the same area and those transactions create a portion of the intersegment revenues shown in the table below.

The contract compression segment includes designing, sourcing, owning, insuring, installing, operating, servicing, repairing, and maintaining compressors and related equipment, with a 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. Revenues in this segment are fee-based, with minimal direct exposure to commodity price risk. The contract compression operations are primarily located in Texas, Louisiana, and Arkansas.  The contract compression segment also provides services to certain operations in the gathering and processing segment, creating a portion of the intersegment revenues shown in the table below.

Management evaluates the performance of each segment and makes capital allocation decisions through the separate consideration of segment margin and operation and maintenance expenses.  Segment margin, for the gathering and processing and for the transportation segments, is defined as total revenues, including service fees, less cost of sales. In the contract compression segment, segment margin is defined as revenues minus direct costs, which primarily consist of compressor repairs. Management believes segment margin is an important measure because it directly relates to volume, commodity price changes and revenue generating horsepower. Operation and maintenance expenses are a separate measure used by management to evaluate performance of field operations.  Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operation and maintenance expenses. These expenses fluctuate depending on the activities performed during a specific period.  The Partnership does not deduct operation and maintenance expenses from total revenues in calculating segment margin because management separately evaluates commodity volume and price changes in segment margin.

18
Results for each statement of operations period, together with amounts related to balance sheets for each segment, are shown below.

   
Gathering and Processing
    
Transportation
    
Contract Compression
    
Corporate
    
Eliminations
    
Total
  
   
(in thousands)
  
External Revenue
                                    
For the three months ended September 30, 2008
  
$
 377,482     $ 133,620     $ 36,073     $ -     $ -     $ 547,175  
For the three months ended September 30, 2007
     199,717       96,107       -       -       -       295,824  
For the nine months ended September 30, 2008
     977,773       427,326