Attached files

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EX-31.1 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER - Regency Energy Partners LPdex311.htm
EX-32.1 - SECTION 1350 CERTIFICATIONS OF CHIEF EXECUTIVE OFFICER - Regency Energy Partners LPdex321.htm
EX-31.2 - RULE 13A-14(A)/15D-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER - Regency Energy Partners LPdex312.htm
EX-32.2 - SECTION 1350 CERTIFICATIONS OF CHIEF FINANCIAL OFFICER - Regency Energy Partners LPdex322.htm
EX-10.46 - MERGER AGREEMENT - Regency Energy Partners LPdex1046.htm
EX-10.45 - PURCHASE AND SALE AGREEMENT - Regency Energy Partners LPdex1045.htm
EX-12.1 - COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES - Regency Energy Partners LPdex121.htm

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

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

For the quarterly period ended June 30, 2010

OR

 

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

For the transition period from              to             

Commission File Number: 000-51757

 

 

REGENCY ENERGY PARTNERS LP

(Exact name of registrant as specified in its charter)

 

 

 

DELAWARE   16-1731691

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification No.)

2001 BRYAN STREET, SUITE 3700

DALLAS, 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.    x  Yes    ¨  No

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

Indicate by check mark 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   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

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

The issuer had 119,618,704 common units outstanding as of August 2, 2010.

 

 

 


Introductory Statement

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

 

Name

  

Definition or Description

Bcf/d

   One billion cubic feet per day

EFS Haynesville

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

Enterprise GP

   Enterprise GP Holdings, LP

ETC II

   ETC Midcontinent Express Pipeline II L.L.C., a 100 percent owned subsidiary of ETP

ETC III

   ETC Midcontinent Express Pipeline III L.L.C., a 100 percent owned subsidiary of ETP

ETE

   Energy Transfer Equity, L.P.

ETE GP

   ETE GP Acquirer LLC

ETP

   Energy Transfer Partners, L.P.

FASB

   Financial Accounting Standards Board

FERC

   Federal Energy Regulatory Commission

Finance Corp.

   Regency Energy Finance Corp., a 100 percent owned subsidiary of the Partnership

GAAP

   Accounting principles generally accepted in the United States

GE

   General Electric Company

GECC

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

GE EFS

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

General Partner

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

GP Seller

   Regency GP Acquirer, L.P.

HPC

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

LIBOR

   London Interbank Offered Rate

LTIP

   Long-Term Incentive Plan

MEP

   Midcontinent Express Pipeline LLC

MMbtu/d

   One million BTUs per day

MMcf

   One million cubic feet

MMcf/d

   One million cubic feet per day

NGPA

   Natural Gas Policy Act of 1978

NYMEX

   New York Mercantile Exchange

Partnership

   Regency Energy Partners LP

Regency Midcon

   Regency Midcontenent Express LLC, a 100 percent owned subsidiary of the Partnership

RFS

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

RGS

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

RIG

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

RIGS

   Regency Intrastate Gas System

SEC

   Securities and Exchange Commission

WTI

   West Texas Intermediate Crude

 

Page | 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, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,” “forecast,” “may” or similar expressions help identify forward-looking statements. Although we believe our forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, we cannot give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions including, without limitation, the following:

 

   

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

 

   

declines in the credit markets and the availability of credit for us as well as for producers connected to our pipelines and our gathering and processing facilities, and for customers of our contract compression business;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

changes in laws and regulations impacting the midstream sector of the natural gas industry (including those that relate to climate change and environmental protection);

 

   

weather and other natural phenomena;

 

   

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

 

   

regulation of transportation rates on our natural gas pipelines;

 

   

our ability to obtain indemnification for environmental cleanup liabilities and to clean up any hazardous material release on satisfactory terms;

 

   

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 our December 31, 2009 Annual Report on Form 10-K.

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.

 

Page | 3


PART I – FINANCIAL INFORMATION

 

Item 1. Financial Statements

As disclosed in Note 1, on May 26, 2010 GP Seller sold all of the outstanding membership interests of the Partnership’s General Partner to ETE, effecting a change in control of the Partnership. In connection with this transaction, the Partnership’s assets and liabilities were required to be adjusted to fair value at the acquisition date by application of “push-down” accounting. As a result, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor”.

 

Page | 4


Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands except unit data)

 

     Successor           Predecessor  
     June 30,
2010
          December 31,
2009
 
     (unaudited)              
ASSETS          

Current Assets:

         

Cash and cash equivalents

   $ 4,296           $ 9,827   

Restricted cash

     1,011             1,511   

Trade accounts receivable, net of allowance of $475 and $1,130

     22,801             30,433   

Accrued revenues

     76,272             95,240   

Related party receivables

     33,444             6,222   

Derivative assets

     19,833             24,987   

Other current assets

     8,420             10,556   
                     

Total current assets

     166,077             178,776   

Property, Plant and Equipment:

         

Gathering and transmission systems

     488,336             465,959   

Compression equipment

     785,685             823,060   

Gas plants and buildings

     131,537             159,596   

Other property, plant and equipment

     101,046             162,433   

Construction-in-progress

     125,528             95,547   
                     

Total property, plant and equipment

     1,632,132             1,706,595   

Less accumulated depreciation

     (8,740          (250,160
                     

Property, plant and equipment, net

     1,623,392             1,456,435   

Other Assets:

         

Investment in unconsolidated subsidiaries

     1,369,921             453,120   

Long-term derivative assets

     1,241             207   

Other, net of accumulated amortization of debt issuance costs of $564 and $10,743

     34,206             19,468   
                     

Total other assets

     1,405,368             472,795   

Intangible Assets and Goodwill:

         

Intangible assets, net of accumulated amortization of $2,159 and $33,929

     666,781             197,294   

Goodwill

     733,674             228,114   
                     

Total intangible assets and goodwill

     1,400,455             425,408   
                     

TOTAL ASSETS

   $ 4,595,292           $ 2,533,414   
                     
LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST          

Current Liabilities:

         

Trade accounts payable

   $ 43,513           $ 44,912   

Accrued cost of gas and liquids

     75,619             76,657   

Related party payables

     4,417             2,312   

Deferred revenues, including related party amounts of $0 and $338

     11,244             11,292   

Derivative liabilities

     3,576             12,256   

Escrow payable

     1,011             1,511   

Other current liabilities, including related party amounts of $630 and $0

     14,985             12,368   
                     

Total current liabilities

     154,365             161,308   

Long-term derivative liabilities

     52,609             48,903   

Other long-term liabilities

     14,249             14,183   

Long-term debt, net

     1,276,640             1,014,299   

Commitments and contingencies

         

Series A convertible redeemable preferred units, redemption amount of $83,891 and $83,891

     70,850             51,711   

Partners’ Capital and Noncontrolling Interest:

         

Common units (120,676,002 and 94,243,886 units authorized; 119,614,719 and 93,188,353 units issued and outstanding at June 30, 2010 and December 31, 2009)

     2,659,907             1,211,605   

General partner interest

     335,193             19,249   

Accumulated other comprehensive loss

     —               (1,994

Noncontrolling interest

     31,479             14,150   
                     

Total partners’ capital and noncontrolling interest

     3,026,579             1,243,010   
                     

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST

   $ 4,595,292           $ 2,533,414   
                     

See accompanying notes to condensed consolidated financial statements

 

Page | 5


Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)

 

    Successor          Predecessor  
    Period from  Acquisition
(May 26, 2010) to
June 30, 2010
         Period from April  1,
2010 to May 25, 2010
    Three Months Ended
June 30, 2009
 

REVENUES

         

Gas sales, including related party amounts of $447, $0, and $0

  $ 48,103          $ 89,170      $ 106,897   

NGL sales including related party amounts of $18,054, $0, and $0

    28,766            69,033        57,676   

Gathering, transportation and other fees, including related party amounts of $2,086, $3,680, and $2,239

    22,884            45,733        69,231   

Net realized and unrealized (loss) gain from derivatives

    (130         223        12,515   

Other

    3,357            7,336        7,223   
                           

Total revenues

    102,980            211,495        253,542   

OPERATING COSTS AND EXPENSES

         

Cost of sales, including related party amounts of $2,281, $3,198, and $1,453

    74,081            147,262        157,347   

Operation and maintenance

    11,942            21,430        31,974   

General and administrative, including related party amounts of $833, $0, and $0

    7,104            21,809        14,127   

Loss on asset sales, net

    10            19        651   

Depreciation and amortization

    10,995            18,609        26,236   
                           

Total operating costs and expenses

    104,132            209,129        230,335   

OPERATING (LOSS) INCOME

    (1,152         2,366        23,207   

Income from unconsolidated subsidiaries

    8,121            7,959        1,587   

Interest expense, net

    (8,109         (14,114     (19,568

Other income and deductions, net

    (3,510         (624     214   
                           

(LOSS) INCOME BEFORE INCOME TAXES

    (4,650         (4,413     5,440   

Income tax expense (benefit)

    245            83        (515
                           

NET (LOSS) INCOME

  $ (4,895       $ (4,496   $ 5,955   

Net income attributable to noncontrolling interest

    (29         (244     (65
                           

NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP

  $ (4,924       $ (4,740   $ 5,890   
                           
 

Amounts attributable to Series A convertible redeemable preferred units

    668            1,335        —     

General partner’s interest, including IDR

    803            —          741   

Amount allocated to non-vested common units

    —              —          (137
                           

Limited partners’ interest

  $ (6,395       $ (6,075   $ 5,286   
                           
 

Basic and Diluted (loss) earnings per unit:

         

Amount allocated to common units

  $ (6,395       $ (6,075   $ 5,286   

Weighted average number of common units outstanding

    119,600,652            92,832,219        80,550,149   

Basic (loss) income per common unit

  $ (0.05       $ (0.07   $ 0.07   

Diluted (loss) income per common unit

  $ (0.05       $ (0.07   $ 0.06   

Distributions paid per unit

  $ 0.445          $ —        $ 0.445   

See accompanying notes to condensed consolidated financial statements

 

Page | 6


Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)

 

     Successor           Predecessor  
     Period from Acquisition
(May 26, 2010) to
June 30, 2010
          Period from January 1,
2010 to May 25, 2010
    Six Months Ended
June 30, 2009
 

REVENUES

           

Gas sales, including related party amounts of $447, $0, and $0

   $ 48,103           $ 232,063      $ 254,793   

NGL sales including related party amounts of $18,054, $0, and $0

     28,766             166,362        107,261   

Gathering, transportation and other fees, including related party amounts of $2,086, $12,200 and $3,376

     22,884             116,061        142,079   

Net realized and unrealized (loss) gain from derivatives

     (130          (716     26,970   

Other

     3,357             15,477        12,417   
                             

Total revenues

     102,980             529,247        543,520   

OPERATING COSTS AND EXPENSES

           

Cost of sales, including related party amounts of $2,281, $6,564 and $1,700

     74,081             371,871        339,875   

Operation and maintenance

     11,942             53,841        68,016   

General and administrative, including related party amounts of $833, $0, and $0

     7,104             37,212        29,205   

Loss (gain) on asset sales, net

     10             303        (133,280

Depreciation and amortization

     10,995             46,084        54,125   
                             

Total operating costs and expenses

     104,132             509,311        357,941   

OPERATING (LOSS) INCOME

     (1,152          19,936        185,579   

Income from unconsolidated subsidiaries

     8,121             15,872        1,923   

Interest expense, net

     (8,109          (36,459     (33,795

Other income and deductions, net

     (3,510          (3,891     256   
                             

(LOSS) INCOME BEFORE INCOME TAXES

     (4,650          (4,542     153,963   

Income tax expense (benefit)

     245             404        (416
                             

NET (LOSS) INCOME

   $ (4,895        $ (4,946   $ 154,379   

Net income attributable to noncontrolling interest

     (29          (406     (100
                             

NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP

   $ (4,924        $ (5,352   $ 154,279   
                             

Amounts attributable to Series A convertible redeemable preferred units

     668             3,336        —     

General partner’s interest, including IDR

     803             662        4,274   

Amount allocated to non-vested common units

     —               (79     1,217   

Beneficial conversion feature for Class D common units

     —               —          820   
                             

Limited partners’ interest

   $ (6,395        $ (9,271   $ 147,968   
                             

Basic and Diluted (loss) earnings per unit:

           

Amount allocated to common units

   $ (6,395        $ (9,271   $ 147,968   

Weighted average number of common units outstanding

     119,600,652             92,788,319        78,920,074   

Basic (loss) income per common unit

   $ (0.05        $ (0.10   $ 1.87   

Diluted (loss) income per common unit

   $ (0.05        $ (0.10   $ 1.85   

Distributions paid per unit

   $ 0.445           $ 0.445      $ 0.89   
 

Amount allocated to Class D common units

   $ —             $ —        $ 820   

Total number of Class D common units outstanding

     —               —          7,276,506   

Income per Class D common unit due to beneficial conversion feature

   $ —             $ —        $ 0.11   

Distributions paid per unit

   $ —             $ —        $ —     

See accompanying notes to condensed consolidated financial statements

 

Page | 7


Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive (Loss) Income

Unaudited

(in thousands)

 

    Three Months Ended June 30, 2010 and 2009  
    Successor         Predecessor  
    Period from Acquisition
(May 26, 2010) to
June 30, 2010
         Period from April 1,
2010 to May 25, 2010
    Three Months Ended
June 30, 2009
 

Net (loss) income

  $ (4,895       $ (4,496   $ 5,955   

Net hedging amounts reclassified to earnings

    —              (512     (13,644

Net change in fair value of cash flow hedges

    —              8,649        (14,622
                           

Comprehensive (loss) income

  $ (4,895       $ 3,641      $ (22,311

Comprehensive income attributable to noncontrolling interest

    29            244        65   
                           

Comprehensive (loss) income attributable to Regency Energy Partners LP

  $ (4,924       $ 3,397      $ (22,376
                           
    Six Months Ended June 30, 2010 and 2009  
    Successor          Predecessor  
    Period from Acquisition
(May 26, 2010) to June
30, 2010
         Period from January 1,
2010 to May 25, 2010
    Six Months Ended
June 30, 2009
 

Net (loss) income

  $ (4,895       $ (4,946   $ 154,379   

Net hedging amounts reclassified to earnings

    —              2,145        (27,894

Net change in fair value of cash flow hedges

    —              18,486        (9,242
                           

Comprehensive (loss) income

  $ (4,895       $ 15,685      $ 117,243   

Comprehensive income attributable to noncontrolling interest

    29            406        100   
                           

Comprehensive (loss) income attributable to Regency Energy Partners LP

  $ (4,924       $ 15,279      $ 117,143   
                           

See accompanying notes to condensed consolidated financial statements

 

Page | 8


Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

Unaudited

(in thousands)

 

    Successor          Predecessor  
    Period from Acquisition
(May 26, 2010) to
June 30, 2010
         Period from January 1,
2010 to May 25, 2010
    Six Months Ended
June 30, 2009
 

OPERATING ACTIVITIES

         

Net (loss) income

  $ (4,895       $ (4,946   $ 154,379   

Adjustments to reconcile net (loss) income to net cash flows provided by (used in) operating activities:

         

Depreciation and amortization, including debt issuance cost amortization

    11,330            49,363        56,750   

Write-off of debt issuance costs

    —              1,780        —     

Income from unconsolidated subsidiaries

    (8,121         (15,872     (1,923

Derivative valuation changes

    6,921            12,004        (6,293

Loss (gain) on asset sales, net

    10            303        (133,280

Unit-based compensation expenses

    137            12,070        2,750   

Cash flow changes in current assets and liabilities:

         

Trade accounts receivable, accrued revenues, and related party receivables

    13,843            (11,272     38,073   

Other current assets

    585            2,516        3,728   

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

    (15,460         8,649        (39,185

Other current liabilities

    (20,497         22,614        (7,396

Distributions received from unconsolidated subsidiaries

    —              12,446        1,900   

Other assets and liabilities

    (60         (234     (232
                           

Net cash flows (used in) provided by operating activities

    (16,207         89,421        69,271   
                           

INVESTING ACTIVITIES

         

Capital expenditures

    (20,875         (63,787     (119,185

Capital contribution to unconsolidated subsidiaries

    (38,922         (20,210     —     

Acquisitions, net of cash received

    12,848            (75,114     —     

Proceeds from asset sales

    14            10,661        83,182   
                           

Net cash flows (used in) investing activities

    (46,935         (148,450     (36,003
                           

FINANCING ACTIVITIES

         

Net borrowings (repayments) under revolving credit facility

    37,000            199,008        (177,249

Proceeds from issuance of senior notes, net of discount

    —              —          236,240   

Debt issuance costs

    (132         (15,728     (11,939

Partner contributions

    7,436            —          —     

Partner distributions

    —              (86,078     (71,644

Acquisition of assets between entities under common control in excess of historical cost

    —              (16,973     —     

Distributions to noncontrolling interest

    —              (1,135     —     

Proceeds from option exercises

    150            120        —     

Equity issuance costs

    —              (89     —     

Distributions to redeemable convertible preferred units

    —              (1,945     —     

Tax withholding on unit-based vesting

    —              (4,994     —     
                           

Net cash flows provided by (used in) financing activities

    44,454            72,186        (24,592
                           

Net change in cash and cash equivalents

    (18,688         13,157        8,676   

Cash and cash equivalents at beginning of period

    22,984            9,827        599   
                           

Cash and cash equivalents at end of period

  $ 4,296          $ 22,984      $ 9,275   
                           

Supplemental cash flow information:

         

Non-cash capital expenditures

  $ 16,159          $ 18,051      $ 9,480   

Issuance of common units for an acquisition

    584,436            —          —     

Deemed contribution from acquisition of assets between entities under common control

    17,152            —          —     

Release of escrow payable from restricted cash

    —              500        —     

Contribution of fixed assets, goodwill and working capital to HPC

    —              —          263,921   

Contribution receivable

    12,288            —          —     

See accompanying notes to condensed consolidated financial statements

 

Page | 9


Regency Energy Partners LP

Condensed Consolidated Statements of Partners’ Capital and Noncontrolling Interest

Unaudited

(in thousands except unit data)

 

     Regency Energy Partners LP              
     Units                               
     Common    Common
Unitholders
    General
Partner
Interest
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interest
    Total  
Predecessor              

Balance - December 31, 2009

   93,188,353    $ 1,211,605      $ 19,249      $ (1,994   $ 14,150      $ 1,243,010   

Issuance of common units under LTIP, net of forfeitures and tax withholding

   152,075      (4,994     —          —          —          (4,994

Issuance of common units, net of costs

   —        (89     —          —          —          (89

Exercise of common unit options

   —        120        —          —          —          120   

Unit-based compensation expenses

   —        12,070        —          —          —          12,070   

Accrued distributions to phantom units

   —        (473     —          —          —          (473

Acquisition of assets between entities under common control in excess of historical cost

   —        —          (16,973     —          —          (16,973

Partner distributions

   —        (84,504     (1,574     —          —          (86,078

Distributions to noncontrolling interest

   —        —          —          —          (1,135     (1,135

Net (loss) income

   —        (6,014     662        —          406        (4,946

Distributions to Series A convertible redeemable preferred units

   —        (1,906     (39     —          —          (1,945

Accretion of Series A convertible redeemable preferred units

   —        (55     —          —          —          (55

Net cash flow hedge amounts reclassified to earnings

   —        —          —          2,145        —          2,145   

Net change in fair value of cash flow hedges

   —        —          —          18,486        —          18,486   
                                             

Balance - May 25, 2010

   93,340,428    $ 1,125,760      $ 1,325      $ 18,637      $ 13,421      $ 1,159,143   
                                             
     Regency Energy Partners LP              
     Units                               
     Common    Common
Unitholders
    General
Partner
Interest
    Accumulated
Other
Comprehensive
Income (Loss)
    Noncontrolling
Interest
    Total  
Successor              

Balance - May 26, 2010

   93,340,428    $ 2,073,532      $ 304,950      $ —        $ 31,450      $ 2,409,932   

Issuance of common units, net of costs

   26,266,791      584,436        —          —          —          584,436   

Exercise of common unit options

   7,500      150        —          —          —          150   

Unit-based compensation expenses

   —        137        —          —          —          137   

Acquisition of assets between entities under common control below historical cost

   —        —          17,152        —          —          17,152   

Partner contributions

   —        7,436        12,288        —          —          19,724   

Net (loss) income

   —        (5,727     803        —          29        (4,895

Accretion of Series A convertible redeemable preferred units

   —        (57     —          —          —          (57
                                             

Balance - June 30, 2010

   119,614,719    $ 2,659,907      $ 335,193      $ —        $ 31,479      $ 3,026,579   
                                             

See accompanying notes to condensed consolidated financial statements

 

Page | 10


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

Organization. The unaudited condensed consolidated financial statements presented herein contain the results of Regency Energy Partners LP (the “Partnership”) and its subsidiaries. The Partnership and its subsidiaries are engaged in the business of gathering, processing and transporting of natural gas and NGLs as well as providing contract compression services.

Basis of Presentation. On May 26, 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP (the “ETE Acquisition”). Prior to the closing of the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all the outstanding limited partners’ interests in the General Partner, which is the sole general partner of the Partnership, and the entire member’s interest in the Managing General Partner, which is the sole general partner of the General Partner and, by virtue of that position, controlled the Partnership. Control of the Partnership transferred from GE EFS to ETE as a result of the ETE Acquisition. In connection with this transaction, the Partnership’s assets and liabilities were required to be adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting (the “Push-down Adjustments”). Total enterprise value of the Partnership as of May 26, 2010 was $3,783,680,000, giving effect to the transaction and the associated Push-down Adjustments, which is calculated below:

 

     (in thousands)

Fair value of limited partners interest, based on the number of outstanding

  

Partnership common units and the trading price on May 26, 2010

   $ 2,073,532

Fair value of consideration paid for general partner interest

     304,950

Noncontrolling interest

     31,450

Series A convertible redeemable preferred units

     70,793

Fair value of long-term debt

     1,239,863

Other long-term liabilities

     63,092
      

Enterprise value

   $ 3,783,680
      

The Partnership has developed the preliminary amount of the fair value of its assets and liabilities. Management is reviewing the valuation and confirming results to determine the final purchase price allocation. The Partnership allocated the enterprise value to the following assets and liabilities based on their respective estimated fair values as of May 26, 2010:

 

     At May 26, 2010  
     (in thousands)  

Working capital

   $ (3,286

Gathering and transmission systems

     487,792   

Compression equipment

     779,634   

Gas plants and buildings

     131,537   

Other property, plant and equipment

     100,267   

Construction-in-progress

     114,146   

Other long-term assets

     36,839   

Investment in unconsolidated subsidiary

     734,137   

Intangible assets

     668,940   

Goodwill

     733,674   
        
   $ 3,783,680   
        

Due to the Push-down Adjustments, the Partnership’s unaudited condensed consolidated financial statements and certain footnote disclosures are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (1) the period prior to the acquisition date (May 26, 2010), identified as “Predecessor” and (2) the period from May 26, 2010 forward, identified as “Successor”.

The unaudited financial information included in this Form 10-Q has been prepared on the same basis as the audited consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. In the opinion

 

Page | 11


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

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 inter-company 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.

Intangible Assets. Intangible assets, net consist of the following.

 

Predecessor

   Contracts     Customer
Relations
    Trade Names     Permits and
Licenses
    Total  
                 (in thousands)              

Balance at December 31, 2009

   $ 126,332      $ 35,362      $ 30,508      $ 5,092      $ 197,294   

Amortization

     (3,322     (817     (975     (214     (5,328
                                        

Balance at May 25, 2010

   $ 123,010      $ 34,545      $ 29,533      $ 4,878      $ 191,966   
                                        

Successor

   Customer
Relations
    Trade Names     Total        
           (in thousands)          

Balance at May 26, 2010

   $ 604,840      $ 64,100      $ 668,940     

Amortization

     (1,905     (254     (2,159  
                          

Balance at June 30, 2010

   $ 602,935      $ 63,846      $ 666,781     
                          

As of June 30, 2010, customer relations and trade names are amortized over 30 and 20 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)

2010 (remaining)

   $ 11,606

2011

     23,211

2012

     23,211

2013

     23,211

2014

     23,211

Recently Issued Accounting Standards. In June 2009, the FASB issued guidance that significantly changed the consolidation model for variable interest entities. The guidance is effective for annual reporting periods that begin after November 15, 2009, and for interim periods within that first annual reporting period. The Partnership determined that this guidance had no impact on its financial position, results of operations or cash flows upon adoption on January 1, 2010.

In January 2010, the FASB issued guidance requiring improved disclosure of transfers in and out of Levels 1 and 2 for an entity’s fair value measurements, such requirement becoming effective for interim and annual periods beginning after December 15, 2009. Further, additional disclosure of activities such as purchases, sales, issuances and settlements of items relying on Level 3 inputs will be required, such requirements becoming effective for interim and annual periods beginning after December 15, 2010. The Partnership determined that this guidance with respect to Levels 1, 2 and 3 had no impact on its financial position, results of operations or cash flows upon adoption.

In February 2010, the FASB clarified the type of embedded credit derivative that is exempt from embedded derivative bifurcation requirements. The Partnership evaluated the impact of this update on its accounting for embedded derivatives and determined that it had no impact on its financial position, results of operations or cash flows.

2. (Loss) Income per Limited Partner Unit

On September 2, 2009, the Partnership issued 4,371,586 Series A Convertible Redeemable Preferred Units (“Series A Preferred Units”). The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010. Distributions for the quarters ended September 30, 2009 and December 31, 2009 were accrued, effectively increasing the conversion value of the Series A Preferred Units. Distributions are cumulative, and must be paid before any distributions to the general partner and common unitholders. For the purpose of calculating income per limited partner unit, any form of distributions, whether paid or not, as well as the accretion of the Series A Preferred Units, are treated as a reduction in net income (loss) available to the general partner and limited partner interests.

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three and six months ended June 30, 2010 and 2009.

 

Page | 12


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

     Three Months Ended June 30, 2010 and 2009
      Successor           Predecessor
     Period from Acquisition (May 26, 2010)  to
June 30, 2010
          Period from April 1, 2010 to Disposition
(May 25, 2010)
    Three Months Ended June 30, 2009
     Loss
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
          Loss (Numerator)     Units
(Denominator)
   Per-Unit
Amount
    Income
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
     (in thousands except unit and per unit data)           (in thousands except unit and per unit data)

Basic (Loss) Earnings per Unit

                          

Limited partners’ interests

   $ (6,395   119,600,652    $ (0.05        $ (6,075   92,832,219    $ (0.07   $ 5,286      80,550,149    $ 0.07

Effect of Dilutive Securities

                          

Restricted (non-vested) common units

     —        —               —        —          (137   621,337   
                                                  

Diluted (Loss) Earnings per Unit

   $ (6,395   119,600,652    $ (0.05        $ (6,075   92,832,219    $ (0.07   $ 5,149      81,171,486    $ 0.06
                                                  
     Six Months Ended June 30, 2010 and 2009
      Successor           Predecessor
     Period from Acquisition (May 26, 2010) to
June 30, 2010
          Period from January 1, 2010 to Disposition
(May 25, 2010)
    Six Months Ended June 30, 2009
     Loss
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
          Income
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
    Income
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
     (in thousands except unit and per unit data)           (in thousands except unit and per unit data)

Basic (Loss) Earnings per Unit

                          

Limited partners’ interest

   $ (6,395   119,600,652    $ (0.05        $ (9,271   92,788,319    $ (0.10   $ 147,968      78,920,074    $ 1.87

Effect of Dilutive Securities

                          

Restricted (non-vested) common units

     —        —               —        —          1,217      652,740   

Class D common units

     —        —               —        —          820      1,608,068   
                                                  

Diluted (Loss) Earnings per Unit

   $ (6,395   119,600,652    $ (0.05        $ (9,271   92,788,319    $ (0.10   $ 150,005      81,180,882    $ 1.85
                                                

The following table shows the weighted average outstanding amount of securities that could potentially dilute earnings per unit in the future that were not included in the computation of diluted earnings per unit because to do so would have been antidilutive.

 

     Successor          Predecessor
     Period from
Acquisition
(May 26, 2010)
to June 30,
2010
         Period from
April 1, 2010 to
Disposition
(May 25, 2010)
   Three Months
Ended June 30,
2009
   Period from
January 1, 2010
to Disposition
(May 25, 2010)
   Six Months
Ended June 30,
2009

Restricted (non-vested) common units

   —           356,954    —      396,918    —  

Phantom units *

   322,750         351,345    332,860    369,346    332,860

Common unit options

   290,150         290,150    372,768    298,400    376,518

Convertible redeemable preferred units

   4,584,192         4,584,192    —      4,584,192    —  

 

* Amount disclosed assumes maximum conversion rate for market condition awards.

3. Acquisitions

On April 30, 2010, the Partnership purchased an additional 6.99 percent general partner interest in HPC from EFS Haynesville, bringing its total general partner interest in HPC to 49.99 percent. The purchase price of $92,087,000 was funded by borrowings under the Partnership’s revolving credit facility. Because this transaction occurred between two entities under common control, partners’ capital was decreased by $16,973,000, which represented a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount of $75,114,000.

On May 26, 2010, the Partnership purchased a 49.9 percent interest in MEP from ETE. The Partnership issued 26,266,791 common units to ETE, valued at $584,436,000, and received a working capital adjustment of $12,848,000 from ETE that was recorded as an adjustment to investment in unconsolidated subsidiaries. Because this transaction occurred between two entities under common control, partners’ capital was increased by $17,152,000, which represented a deemed contribution of the excess carrying amount of ETE’s investment of $588,740,000 over the purchase price. MEP is a 500 mile natural gas pipeline system that extends from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP.

The following unaudited pro forma financial information has been prepared as if the transactions involving the purchase of 6.99 percent general partner interest in HPC, purchase of the 49.9 percent interest in MEP, together with the Push-down Adjustments described in Note 1 occurred as of the beginning of the earliest period presented. 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 dates referred to above or the results of operations that may be expected in the future.

 

Page | 13


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

     Pro Forma Results for the
     Period from
April 1, 2010 to
May 25, 2010
    Three Months
Ended June 30,
2009
    Period from
January 1, 2010
to May 25, 2010
    Six Months
Ended June 30,
2009
     (in thousands except unit and per unit data)

Total revenues

   $ 211,495      $ 253,542      $ 529,247      $ 531,547

Net (loss) income attributable to Regency Energy Partners LP

   $ (4,361   $ (2,581   $ (6,108   $ 133,911

Amounts attributable to Series A convertible redeemable preferred units

     1,335        —          3,336        —  

General partner’s interest, including IDR

     801        773        1,641        4,270

Amount allocated to non-vested common units

     —          (196     (80     711

Beneficial conversion feature for Class D common units

     —          —          —          820
                              

Limited partners’ interest

   $ (6,497   $ (3,158   $ (11,005   $ 128,110
                              

Basic and Diluted earnings (loss) per unit:

        

Amount allocated to common units

   $ (6,497   $ (3,158   $ (11,005   $ 128,110

Weighted average number of common units outstanding

     119,099,010        106,816,940        119,055,110        105,186,865

Basic (loss) income per common unit

   $ (0.05   $ (0.03   $ (0.09   $ 1.22

Diluted (loss) income per common unit

   $ (0.05   $ (0.03   $ (0.09   $ 1.21

Distributions paid per unit

   $ 0.445      $ 0.445      $ 0.445      $ 0.890

Amount allocated to Class D common units

   $ —        $ —        $ —        $ 820

Total number of Class D common units outstanding

     —          —          —          7,276,506

Income per Class D common unit due to beneficial conversion feature

   $ —        $ —        $ —        $ 0.11

Distributions per unit

   $ —        $ —        $ —        $ —  

4. Investment in Unconsolidated Subsidiaries

Investment in HPC. HPC was established in March 2009 and as of June 30, 2010, the Partnership owns 49.99 percent interest in HPC. Following table summarizes the changes in the Partnership’s investment in HPC.

 

     Successor          Predecessor
     Period from
Acquisition
(May 26, 2010)
to June 30, 2010
         Period from
April 1, 2010 to
Disposition (May
25, 2010)
   Three Months
Ended June 30,
2009
   Period from
January 1, 2010
to Disposition
(May 25, 2010)
   Six Months
Ended June 30,
2009
     (in thousands)          (in thousands)

Contributions to HPC

   $ —           $ 20,210    $ —      $ 20,210    $ 400,000

Distributions received from HPC

     —             8,920      1,900      12,446      1,900

Partnership’s share of HPC’s net income

     4,460           7,959      1,587      15,872      1,923

As discussed in Note 1, the Partnership’s investment in HPC was adjusted to its fair value on May 26, 2010 and the excess fair value over net book value was comprised of two components: (1) $143,757,000 was attributed to HPC’s long-lived assets and is being amortized as a reduction of income from unconsolidated subsidiaries over the useful lives of the respective assets, which vary from 15 to 30 years, and (2) $38,510,000 could not be attributed to a specific asset and therefore will not be amortized in future periods. For the period from May 26, 2010 to June 30, 2010, the Partnership recorded $365,000 as a reduction of income from unconsolidated subsidiaries due to the amortization of the excess fair value of long-lived assets.

The summarized financial information of HPC is disclosed below.

 

Page | 14


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheets

(in thousands)

 

     June 30, 2010    December 31, 2009
     (Unaudited)     
ASSETS          

Total current assets

   $ 48,383    $ 39,239

Restricted cash, non-current

     43,314      33,595

Property, plant and equipment, net

     888,542      861,570

Total other assets

     149,065      149,755
             

TOTAL ASSETS

   $ 1,129,304    $ 1,084,159
             
LIABILITIES & PARTNERS’ CAPITAL      

Total current liabilities

   $ 17,273    $ 30,967

Partners’ capital

     1,112,031      1,053,192
             

TOTAL LIABILITIES & PARTNERS’ CAPITAL

   $ 1,129,304    $ 1,084,159
             

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statements

(in thousands)

 

          For the Six
Months Ended
June 30, 2010
    From Inception
(March 18, 2009) to
June 30, 2009
     For the Three
Months Ended
June 30,
    
     2010     2009     
     (Unaudited)    (Unaudited)

Total revenues

   $ 44,375      $ 11,707    $ 79,564      $ 13,533

Total operating costs and expenses

     18,425        8,038      35,148        9,084
                             

OPERATING INCOME

     25,950        3,669      44,416        4,449

Interest expense

     (99     —        (201     —  

Other income and deductions, net

     20        508      59        612
                             

NET INCOME

   $ 25,871      $ 4,177    $ 44,274      $ 5,061
                             

Investment in MEP. On May 26, 2010, the Partnership purchased a 49.9 interest in the MEP from ETE. In June 2010, the Partnership made an additional capital contribution of $38,922,000 to MEP. During the period from May 26, 2010 to June 30, 2010, the Partnership recognized $4,026,000 in income from unconsolidated subsidiaries for its ownership interest.

The summarized financial information of MEP is disclosed below.

Midcontinent Express Pipeline LLC

Condensed Balance Sheet

(in thousands)

 

      June 30, 2010
     (Unaudited)
ASSETS   

Total current assets

   $ 32,987

Property, plant and equipment, net

     2,225,383

Total other assets

     5,588
      

TOTAL ASSETS

   $ 2,263,958
      
LIABILITIES & PARTNERS’ CAPITAL   

Total current liabilities

   $ 92,795

Long-term debt

     800,000

Partners’ capital

     1,371,163
      

TOTAL LIABILITIES & PARTNERS’ CAPITAL

   $ 2,263,958
      

 

Page | 15


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

Midcontinent Express Pipeline LLC

Condensed Income Statement

(in thousands)

 

     Month Ended June 30, 2010  
     (Unaudited)  

Total revenues

   $ 21,269   

Total operating costs and expenses

     9,770   
        

OPERATING INCOME

     11,499   

Interest expense, net

     (3,431
        

NET INCOME

   $ 8,068   
        

5. Derivative Instruments

Policies. The Partnership has established comprehensive risk management policies and procedures to monitor and manage the market risks associated with commodity prices, counterparty credit, and interest rates. The General Partner is responsible for delegation of transaction authority levels, and the Risk Management Committee of the General Partner is responsible for the overall management of these risks, including monitoring exposure limits. The Risk Management Committee receives regular briefings on exposures and overall risk management in the context of market activities.

Commodity Price Risk. The Partnership is a net seller of NGLs, condensate and natural gas as a result of its gathering and processing operation. The prices of these commodities are impacted by changes in the supply and demand as well as market focus. Both the Partnership’s profitability and cash flow are affected by the inherent volatility of these commodities which could adversely affect its ability to make distributions to its unitholders. The Partnership manages this commodity price exposure through an integrated strategy that includes management of its contract portfolio, matching sales prices of commodities with purchases, optimization of its portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, the Partnership may not be able to match pricing terms or to cover its risk to price exposure with financial hedges, and it may be exposed to commodity price risk. Speculative positions with derivative contracts are prohibited under the Partnership’s policies.

On May 26, 2010, all of the Partnership’s outstanding commodity swaps that were previously accounted for as cash flow hedges were de-designated and are currently accounted for under the mark-to-market method of accounting.

The Partnership executes natural gas, NGLs’ and WTI trades on a periodic basis to hedge its anticipated equity exposure. Subsequent to June 30, 2010, the Partnership has executed additional NGL swaps to hedge its 2011 and 2012 price exposure.

The Partnership has executed swap contracts settled against NGLs (ethane, propane, butane and natural gasoline), condensate and natural gas market prices for expected equity exposure in the approximate percentages set forth.

 

     As of June 30, 2010     As of August 8, 2010  
     2010     2011     2012     2010     2011     2012  

NGLs

   87   52   0   87   67   6

Condensate

   96   74   7   96   74   7

Natural gas

   74   42   0   74   42   0

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its revolving credit facility. As of June 30, 2010, the Partnership had $655,650,000 of outstanding borrowings exposed to variable interest rate risk. The Partnership’s $300,000,000 interest rate swaps expired in March 2010. In April 2010, the Partnership entered into additional two-year interest rate swaps related to $250,000,000 of borrowings under its revolving credit facility, effectively locking the base rate, exclusive of applicable margins, for these borrowings at 1.325 percent through April 2012.

Credit Risk. The Partnership’s resale of natural gas exposes it to credit risk, as the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to overall profitability on these transactions. The Partnership attempts to ensure that it issues credit only to credit-worthy counterparties and that in appropriate circumstances extension of credit is backed by adequate collateral such as a letter of credit or parental guarantee.

The Partnership is exposed to credit risk from its derivative counterparties. The Partnership does not require collateral from these counterparties. The Partnership deals primarily with financial institutions when entering into financial derivatives. The Partnership has entered into Master International Swap Dealers Association (“ISDA”) Agreements that allow for netting of swap contract

 

Page | 16


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

receivables and payables in the event of default by either party. If the Partnership’s counterparties fail to perform under existing swap contracts, the Partnership’s maximum loss would be $21,346,000, which would be reduced by $2,824,000 due to the netting feature. The Partnership has elected to present assets and liabilities under Master ISDA Agreements gross on the condensed consolidated balance sheets.

Embedded Derivatives. The Series A Preferred Units contain embedded derivatives which are required to be bifurcated and accounted for separately, such as the holders’ conversion option and the Partnership’s call option. These embedded derivatives are accounted for using mark-to-market accounting. The Partnership does not expect the embedded derivatives to affect its cash flows.

The Partnership’s derivative assets and liabilities, including credit risk adjustment, as of June 30, 2010 and December 31, 2009 are detailed below.

 

     Assets    Liabilities
     June 30, 2010
(unaudited)
   December 31, 2009    June 30, 2010
(unaudited)
   December 31, 2009
     (in thousands)

Derivatives designated as cash flow hedges

           

Current amounts

           

Interest rate contracts

   $ —      $ —      $ —      $ 1,064

Commodity contracts

     —        9,521      —        11,161

Long-term amounts

           

Commodity contracts

     —        207      —        931
                           

Total cash flow hedging instruments

     —        9,728      —        13,156
                           

Derivatives not designated as cash flow hedges

           

Current amounts

           

Commodity contracts

     19,833      15,466      2,052      31

Interest rate contracts

     —        —        1,524      —  

Long-term amounts

           

Commodity contracts

     1,241      —        15      3,378

Interest rate contracts

     —        —        355   

Embedded derivatives in Series A Preferred Units

     —        —        52,239      44,594
                           

Total derivatives not designated as cash flow hedges

     21,074      15,466      56,185      48,003
                           

Total derivatives

   $ 21,074    $ 25,194    $ 56,185    $ 61,159
                           

The following tables detail the effect of the Partnership’s derivative assets and liabilities in the consolidated statement of operations for the period presented.

 

Page | 17


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

For the Three Months Ended June 30, 2010 and 2009

 

            Successor           Predecessor  
          Period from May 26,
2010 through June 30,
2010
          Period from April 1, 2010
through May 25, 2010
    For the Three Months
Ended June 30, 2009
 
          (in thousands)           (in thousands)  
          Change in Value Recognized in
OCI on Derivatives (Effective Portion)
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

      —             7,428      (13,946

Interest rate swap derivatives

      —             —        (676
                          
      —             7,428      (14,622
                          
          Amount of Gain/(Loss) Reclassified from  AOCI
into Income (Effective Portion)
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    —             (709   15,546   

Interest rate swap derivatives

   Interest expense    —             —        (1,515
                          
      —             (709   14,031   
                          
          Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    —             (301   1,616   

Interest rate swap derivatives

   Interest expense    —             —        —     
                          
      —             (301   1,616   
                          
          Amount of Gain/(Loss) from  Dedesignation
Amortized from AOCI into Income
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    —             1,221      (387

Interest rate swap derivatives

   Interest expense    —             —        —     
                          
      —             1,221      (387
                          
          Amount of Gain/(Loss) Recognized
in Income on Derivatives
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    (824        12      (5,690

Interest rate swap derivatives

   Interest expense    (1,715        (824   —     

Embedded derivative

   Other income & deductions    (3,606        (654   —     
                          
      (6,145        (1,466   (5,690
                          

 

Page | 18


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

For the Six Months Ended June 30, 2010 and 2009

 

            Successor           Predecessor  
          Period from May 26,
2010 through June 30,
2010
          Period from January 1,
2010 through May 25,
2010
    For the Six Months Ended
June 30, 2009
 
          (in thousands)                 (in thousands)  
          Change in Value Recognized in
OCI on Derivatives (Effective Portion)
 

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

      —             14,371      (7,728

Interest rate swap derivatives

      —             —        (1,514
                          
      —             14,371      (9,242
                          
          Amount of Gain/(Loss) Reclassified from AOCI
into Income (Effective Portion)
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    —             (5,200   32,065   

Interest rate swap derivatives

   Interest expense    —             (1,060   (2,987
                          
      —             (6,260   29,078   
                          
          Amount of Gain/(Loss) Recognized in
Income on Ineffective Portion
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives in cash flow hedging relationships:

              

Commodity derivatives

   Revenues    —             (799   2,231   

Interest rate swap derivatives

   Interest expense    —             —        —     
                          
      —             (799   2,231   
                          
          Amount of Gain/(Loss) from Dedesignation
Amortized from AOCI into Income
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    —             4,115      (1,184

Interest rate swap derivatives

   Interest expense    —             —        —     
                          
      —             4,115      (1,184
                          
          Amount of Gain/(Loss) Recognized
in Income on Derivatives
 
     Location of Gain (Loss)
Recognized in Income
                        

Derivatives not designated in a hedging relationship:

              

Commodity derivatives

   Revenues    (824        1,247      (7,092

Interest rate swap derivatives

   Interest expense    (1,715        (824   —     

Embedded derivative

   Other income & deductions    (3,606        (4,039   —     
                          
      (6,145        (3,616   (7,092
                          

6. Long-term Debt

The following table provides information on the Partnership’s long-term debt.

 

     June 30, 2010     December 31, 2009  
     (in thousands)  

Senior notes

   $ 620,990      $ 594,657   

Revolving loans

     655,650        419,642   
                

Total

     1,276,640        1,014,299   

Less: current portion

     —          —     
                

Long-term debt

   $ 1,276,640      $ 1,014,299   
                

Availability under revolving credit facility:

    

Total credit facility limit

   $ 900,000      $ 900,000   

Unfunded commitments

     —          (10,675

Revolving loans

     (655,650     (419,642

Letters of credit

     (17,032     (16,257
                

Total available

   $ 227,318      $ 453,426   
                

Long-term debt maturities as of June 30, 2010 for each of the next five years are as follows:

 

Page | 19


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

Year Ending December 31,

   Amount
     (in thousands)

2010

   $ —  

2011

     —  

2012

     —  

2013

     357,500

2014

     655,650

Thereafter

     250,000
      

Total

   $ 1,263,150
      

The outstanding balance of revolving debt under the revolving credit facility bears interest at LIBOR plus a margin or Alternate Base Rate (equivalent to the U.S prime rate lending rate) plus a margin or a combination of both. The senior notes pay fixed interest rates and the weighted average coupon rate is 8.787 percent. 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 5.74 percent during the period from May 26, 2010 to June 30, 2010, 7.98 percent during the period from April 1, 2010 to May 25, 2010, 6.69 percent during the three months ended June 30, 2009, 7.98 percent during the period from January 1, 2010 to May 25, 2010 and 5.94 percent during the six months ended June 30, 2009.

Senior Notes. The senior notes are jointly and severally guaranteed by all of the Partnership’s current consolidated subsidiaries, other than Finance Corp., and by certain of its future subsidiaries. The senior notes and the guarantees are unsecured and rank equally with all of the Partnership’s and the guarantors’ existing and future unsubordinated obligations. The senior notes and the guarantees will be senior in right of payment to any of the Partnership’s and the guarantors’ future obligations that are, by their terms, expressly subordinated in right of payment to the notes and the guarantees. The senior notes and the guarantees will be effectively subordinated to the Partnership’s and the guarantors’ secured obligations, including the Partnership’s credit facility and the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the terms of the senior notes.

Finance Corp. has no operations and will not have revenues other than as may be incidental as co-issuer of the senior notes. Since the Partnership has no independent operations, the guarantees are fully unconditional and joint and several of its subsidiaries, except certain wholly owned subsidiaries, the Partnership has not included condensed consolidated financial information of guarantors of the senior notes.

Upon a change in control, each holder of the Partnership’s senior notes may, at its option, require the Partnership to purchase all or a portion of its notes at a purchase price of 101 percent plus accrued interest and liquidated damages, if any. Subsequent to the ETE Acquisition, no noteholder has exercised this option.

As disclosed in Note 1, the Partnership’s long-term debt was adjusted to fair value on May 26, 2010. The fair value of the senior notes was adjusted based on quoted market prices. The re-measurement of the senior notes due 2013 and 2016 resulted in premium of $7,150,000 and $6,563,000, respectively.

The unamortized premium or discount on the Partnership’s senior notes as of June 30, 2010 and December 31, 2009 are as follows.

 

Page | 20


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

     Successor         Predecessor  
     June 30, 2010         December 31, 2009  
    

(in thousands)

 

Senior Notes Due 2013

          

Principal amount

   $ 357,500         $ 357,500   

add:

          

Unamortized premium

     6,998           —     
                    

Carrying value

   $ 364,498         $ 357,500   
                    
 

Senior Notes Due 2016

          

Principal amount

   $ 250,000         $ 250,000   

add/ deduct:

          

Unamortized premium (discount)

     6,492           (12,843
                    

Carrying value

   $ 256,492         $ 237,157   
                    

Revolving Credit Facility. On March 4, 2010, RGS executed the Fifth Amended and Restated Credit Agreement (the “new credit agreement”), to be effective as of March 4, 2010. The material differences between the Fourth Amended and Restated Credit Agreement (the “previous credit agreement”) and the new credit agreement include:

 

   

extension of the maturity date to June 15, 2014 from August 15, 2011, subject to the following contingency:

 

   

if the Partnership’s 8.375 percent senior notes due December 15, 2013 have not been refinanced or paid off by June 15, 2013, then the maturity date of the revolving credit facility will be June 15, 2013;

 

   

an increase in the amount of allowed investments in HPC to $250,000,000 from $135,000,000;

 

   

the addition of an allowance for joint venture investments (other than HPC) of up to $75,000,000, provided that (i) distributed cash and net income from joint ventures under this basket shall be excluded from consolidated net income and (ii) equity interests in joint ventures created under this basket shall be pledged as collateral;

 

   

the modification of financial covenants to give credit for projected EBITDA associated with certain future material HPC projects on a percentage of completion basis, provided that such amount, together with adjustments related to the Haynesville Expansion Project and other material projects, does not exceed 20 percent of consolidated EBITDA (as defined in the new credit agreement) through March 31, 2010, and 15 percent thereafter;

 

   

an increase in the annual general asset sales permitted from $20,000,000 annually to five percent of consolidated net tangible assets (as defined in the new credit agreement) annually.

The Partnership treated the amendment of the credit facility as a modification of an existing revolving credit agreement and, therefore, wrote off debt issuance costs of $1,780,000 to interest expense, net in the period from January 1, 2010 to May 25, 2010. In addition, the Partnership paid and capitalized $15,861,000 of loan fees which will be amortized over the remaining term of the credit facility.

On May 26, 2010, the Partnership entered into the first amendment to its Fifth Amended and Restated Credit Agreement. The amendment, among other things,

 

   

amends the definition of “Consolidated EBITDA” and “Consolidated Net Income” to include MEP;

 

   

amends the definition of “Joint Venture” in the credit agreement to include MEP;

 

   

amends the definition of “Permitted Acquisition” in the agreement to clarify that the initial investment in MEP is a permitted acquisition;

 

   

amends the definition of “Permitted Holder” to include to include ETE as a party that may hold the equity interest in the Managing General Partner without triggering an event of default under the credit agreement;

 

   

allows for the pledge of the equity interest in MEP as a collateral indirectly, through the direct pledge of equity interest in Regency Midcon;

 

   

permits certain investments in MEP by the Partnership and its affiliates;

 

   

requires that the Partnership and its subsidiaries maintain a senior consolidated secured leverage ratio not to exceed 3 to 1.

 

Page | 21


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The new credit agreement and the guarantees are senior to the Partnership’s and the guarantors’ secured obligations, including the Series A Preferred Units, to the extent of the value of the assets securing such obligations. As of June 30, 2010, the Partnership was in compliance with each of the financial covenants required under the term of the credit agreement.

7. Commitments and Contingencies

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

Escrow Payable. At June 30, 2010, $1,011,000 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 and a subsequent 2008 settlement agreement between the Partnership and El Paso. In the El Paso PSA, El Paso indemnified Regency Gas Services LLC, now known as Regency Gas Services LP, 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. This escrow amount will be further reduced under a specified schedule as El Paso completes its cleanup obligations and the remainder will be released upon completion. In connection with this matter, $500,000 was released on May 6, 2010.

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 against the Partnership or under the policy.

Keyes Litigation. In August 2008, Keyes Helium Company, LLC (“Keyes”) filed suit against Regency Gas Services LP, the Partnership, the General Partner and various other subsidiaries. Keyes entered into an output contract with the Partnership’s predecessor-in-interest in 1996 under which it purchased all of the helium produced at the Lakin, Kansas processing plant. In September 2004, the Partnership decided to shut down its Lakin plant and contract with a third party for the processing of volumes processed at Lakin; as a result, the Partnership no longer delivered any helium to Keyes. In its suit, Keyes alleges it is entitled to damages for the costs of covering its purchases of helium. On May 7, 2010, the jury rendered a verdict in favor of Regency. No damages were awarded to the Plaintiffs. Plaintiffs have appealed the verdict. The hearing on appeal will take place sometime in 2011.

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. The Kansas Department of Revenue has advised the Partnership that a portion of its condensate sales in Kansas is subject to severance tax; therefore the Partnership will be subject to additional taxes on future condensate sales. The Partnership may also be subject to additional taxes, interest and possible penalties for past condensate sales.

Remediation of Groundwater Contamination at Calhoun and Dubach Plants. Regency Field Services LLC (“RFS”) currently owns the Dubach and Calhoun gas processing plants in north Louisiana (the “Plants”). The Plants each have groundwater contamination as result of historical operations. At the time that RFS acquired the Plants from El Paso Field Services LP (“El Paso”), Kerr-McGee Corporation (“Kerr-McGee”) was performing remediation of the groundwater contamination, because the Plants were once owned by Kerr-McGee and when Kerr-McGee sold the Plants to a predecessor of El Paso in 1988, Kerr-McGee retained liability for any environmental contamination at the Plants. In 2005, Kerr-McGee created and spun off Tronox and Tronox allegedly assumed certain of Kerr-McGee’s environmental remediation obligations (including its obligation to perform remediation at the Plants) prior to the acquisition of Kerr-McGee by Anadarko Petroleum Corporation. In January 2009, Tronox filed for Chapter 11 bankruptcy protection. RFS filed a claim in the bankruptcy proceeding relating to the environmental remediation work at the Plants. Tronox has thus far

continued its remediation efforts at the Plants. Tronox filed a reorganization plan on July 7, 2010. The plan calls for the creation of a trust to fund environmental clean-up at the various sites where Tronox has an obligation. Tronox must file the Environmental Claims Settlement Agreement, which will set forth the amount of trust funds allocated to each site, 14 days prior to the confirmation hearing, the date for which has not yet been set.

 

Page | 22


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

8. Series A Convertible Redeemable Preferred Units

On September 2, 2009, the Partnership issued 4,371,586 Series A Preferred Units. As of March 31, 2010, the Series A Preferred Units were convertible to 4,584,192 common units, and if outstanding, are mandatorily redeemable on September 2, 2029 for $80,000,000 plus all accrued but unpaid distributions thereon. The Series A Preferred Units receive fixed quarterly cash distributions of $0.445 per unit beginning with the quarter ending March 31, 2010, if outstanding on the record dates of the Partnership’s common units distributions. Effective as of March 2, 2010, holders can elect to convert Series A Preferred Units to common units at any time in accordance with the partnership agreement.

Upon a change in control, each unitholder may, at its option, require the Partnership to purchase the Series A Preferred Units for an amount equal to 101 percent of the total of the face value of the Series A Preferred Units plus all accrued but unpaid distribution thereon. Subsequent to the ETE Acquisition, no unitholder has exercised this option.

As disclosed in Note 1, the Partnership’s Series A Preferred Units were adjusted to fair value of $70,793,000 on May 26, 2010. The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the six months ended June 30, 2010.

 

     For the Six Months Ended
June 30, 2010,
 
     Units    Amount  
          (in thousands)  

Beginning balance as of January 1, 2010

   4,371,586    $ 51,711   

Accretion to redemption value from January 1, 2010 to May 25, 2010

   —        55   
             

Balance as of May 25, 2010

   4,371,586      51,766   

Fair value adjustment

   —        19,027   
             

Balance as of May 26, 2010

   4,371,586      70,793   

Accretion to redemption value from May 26, 2010 to June 30, 2010

   —        57   
             

Ending balance as of June 30, 2010

   4,371,586    $ 70,850
             

 

* This amount will be accreted to $80,000,000 plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the 19.25 remaining years.

9. Related Party Transactions

The employees operating the assets of the Partnership and its subsidiaries and all those providing staff or support services are employees of the General Partner. Pursuant to the Partnership Agreement, the General Partner receives a monthly reimbursement for all direct and indirect expenses incurred on behalf of the Partnership. Reimbursements of $5,660,000, $10,370,000, $31,065,000, $8,591,000 and $16,209,000, were recorded in the Partnership’s financial statements during the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010 and for the three and six months ended June 30, 2009, respectively, as operating expenses or general and administrative expenses, as appropriate.

In conjunction with distributions by the Partnership to its limited and general partner interests, GE EFS received cash distributions of $13,114,000, $2,603,000, $26,241,000 and $12,181,000 during the period from April 1, 2010 to May 25, 2010, the three months ended June 30, 2009, the period from January 1, 2010 to May 25, 2010 and the six months ended June 30, 2009, respectively.

Under a Master Services Agreement with HPC, the Partnership operates and provides all employees and services for the operation and management of HPC. Under this agreement, the Partnership receives $1,400,000 monthly as a partial reimbursement of its general and administrative costs. The amount is recorded as fee revenue in the Partnership’s corporate and other segment. The Partnership also incurs expenditures on behalf of HPC and these amounts are billed to HPC on a monthly basis. For the periods from May 26, 2010 to June 30, 2010, from April 1, 2010 to May 25, 2010, from January 1, 2010 to May 25, 2010, and the three and six months ended June 30, 2009, the related party general and administrative expenses reimbursed to the Partnership were $1,400,000, $2,800,000, $6,933,000, $1,500,000, and $1,726,000, respectively.

On May 26, 2010, the Partnership received $7,436,000 from ETE, which represents the portion of the estimated amount of the Partnership’s common unit distribution to be paid to ETE for the period of time those units were not outstanding (April 1, 2010 to May 25, 2010).

As of June 30, 2010, the Partnership has a related party receivable of $12,288,000 from ETE for an additional capital contribution, which was received on August 6, 2010.

 

Page | 23


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

On May 26, 2010, the Partnership entered into a services agreement with ETE and ETE Services Company, LLC (“Services Co.”), a subsidiary of ETE. Under the services agreement, Services Co. will perform certain general and administrative services to the Partnership. The Partnership will pay Services Co’s direct expenses for these services, plus an annual fee of $10,000,000, and will receive the benefit of any cost savings recognized for these services. The services agreement has a five year term, subject to earlier termination rights in the event of a change in control, the failure to achieve certain cost savings for the Partnership or upon an event of default.

As disclosed in Note 3, the Partnership’s acquisition of additional 6.99 percent partner’s interest in HPC from GE EFS, and the 49.9 percent interest in MEP from ETE are related party transactions.

The Partnership’s contract compression segment provides contract compression services to HPC and records revenue in gathering, transportation and other fees on the statement of operation. The Partnership also receives transportation services from HPC and records the cost as cost of sales.

Enterprise GP holds a non-controlling equity interest in ETE’s general partner and a limited partnership interest in ETE, therefore is considered a related party along with any of its subsidiaries. The Partnership, in the ordinary course of business, sells natural gas and NGLs to the subsidiaries of Enterprise GP and records the revenue in gas sales and NGL sales. The Partnership also incurs NGL processing fees with subsidiaries of Enterprise GP and records the cost to cost of sales.

As of June 30, 2010, the Partnership’s related party receivables and related party payables included $18,501,000 and $422,000, respectively, from and to subsidiaries of Enterprise GP.

10. Segment Information

In 2009, the Partnership’s management realigned the composition of its segments. Accordingly, the Partnership has restated the items of segment information for earlier periods to reflect this new alignment.

The Partnership has four reportable segments: (a) gathering and processing, (b) transportation, (c) contract compression and (d) corporate and others. 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 Partnership, through its producer services function, primarily purchases natural gas from producers at gathering systems and plants connected to its pipeline systems and sells this gas at downstream outlets.

The transportation segment consists of the Partnership’s 49.99 percent interest in HPC, which we operate, and the 49.9 percent interest in MEP. Prior periods have been restated to reflect the Partnership’s then wholly-owned subsidiary of Regency Intrastate Gas LLC as the exclusive reporting unit within this segment. The transportation segment uses pipelines to transport natural gas from receipt points on its system to interconnections with other pipelines, storage facilities or end-use markets. RIG 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 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 provides customers with turn-key natural gas compression services to maximize their natural gas and crude oil production, throughput, and cash flow. The Partnership’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 needs. The Partnership is responsible for the installation and on-going operation, service, and repair of its compression units, which are modified as necessary to adapt to customers’ changing operating conditions. 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.

The corporate and others segment comprises regulated entities and the Partnership’s corporate offices. Revenues in this segment include the collection of the partial reimbursement of general and administrative costs from HPC.

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 revenues generating

 

Page | 24


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

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.

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

 

     Gathering and
Processing
    Transportation     Contract
Compression
   Corporate
and  Others
    Eliminations     Total
     (in thousands)

External Revenues

             

Period from May 26, 2010 to June 30, 2010

   $ 90,147      $ —        $ 12,053    $ 780      $ —        $ 102,980

Period from April 1, 2010 to May 25, 2010

     183,582        —          23,992      3,921        —          211,495

For the three months ended June 30, 2009

     209,939        1,531        39,011      3,061        —          253,542

Period from January 1, 2010 to May 25, 2010

     460,423        —          58,971      9,853        —          529,247

For the six months ended June 30, 2009

     453,093        9,075        77,499      3,853        —          543,520

Intersegment Revenues

             

Period from May 26, 2010 to June 30, 2010

     —          —          1,999      22        (2,021     —  

Period from April 1, 2010 to May 25, 2010

     —          —          3,794      53        (3,847     —  

For the three months ended June 30, 2009

     (6,745     (128     975      40        5,858        —  

Period from January 1, 2010 to May 25, 2010

     —          —          9,126      91        (9,217     —  

For the six months ended June 30, 2009

     (8,755     4,936        1,785      144        1,890        —  

Cost of Sales

             

Period from May 26, 2010 to June 30, 2010

     73,311        —          1,564      (772     (22     74,081

Period from April 1, 2010 to May 25, 2010

     144,768        —          2,460      87        (53     147,262

For the three months ended June 30, 2009

     144,816        1,243        4,186      269        6,833        157,347

Period from January 1, 2010 to May 25, 2010

     366,900        —          5,741      (679     (91     371,871

For the six months ended June 30, 2009

     327,284        2,297        6,504      116        3,674        339,875

Segment Margin

             

Period from May 26, 2010 to June 30, 2010

     16,836        —          12,488      1,574        (1,999     28,899

Period from April 1, 2010 to May 25, 2010

     38,814        —          25,326      3,887        (3,794     64,233

For the three months ended June 30, 2009

     58,378        160        35,800      2,832        (975     96,195

Period from January 1, 2010 to May 25, 2010

     93,523        —          62,356      10,623        (9,126     157,376

For the six months ended June 30, 2009

     117,054        11,714        72,780      3,881        (1,784     203,645

Operation and Maintenance

             

Period from May 26, 2010 to June 30, 2010

     8,814        —          4,924      203        (1,999     11,942

Period from April 1, 2010 to May 25, 2010

     15,400        —          9,698      126        (3,794     21,430

For the three months ended June 30, 2009

     22,044        (174     11,487      (181     (1,202     31,974

Period from January 1, 2010 to May 25, 2010

     39,161        —          23,476      327        (9,123     53,841

For the six months ended June 30, 2009

     44,349        2,112        24,028      132        (2,605     68,016

Depreciation and Amortization

             

Period from May 26, 2010 to June 30, 2010

     7,413        —          3,323      259          10,995

Period from April 1, 2010 to May 25, 2010

     11,576        —          6,353      680        —          18,609

For the three months ended June 30, 2009

     16,413        —          8,955      868        —          26,236

Period from January 1, 2010 to May 25, 2010

     28,864        —          15,560      1,660        —          46,084

For the six months ended June 30, 2009

     33,134        2,448        16,982      1,561        —          54,125

Income from Unconsolidated Subsidiaries

             

Period from May 26, 2010 to June 30, 2010

     —          8,121        —        —            8,121

Period from April 1, 2010 to May 25, 2010

     —          7,959        —        —          —          7,959

For the three months ended June 30, 2009

     —          1,587        —        —          —          1,587

Period from January 1, 2010 to May 25, 2010

     —          15,872        —        —            15,872

For the six months ended June 30, 2009

     —          1,923        —        —          —          1,923

Assets

             

June 30, 2010

     1,751,253        1,369,921        1,362,549      111,569        —          4,595,292

December 31, 2009

     1,046,619        453,120        926,213      107,462        —          2,533,414

Investment in Unconsolidated Subsidiaries

             

June 30, 2010

     —          1,369,921        —        —          —          1,369,921

December 31, 2009

     —          453,120        —        —          —          453,120

Goodwill

             

June 30, 2010

     286,634        —          447,040      —          —          733,674

December 31, 2009

     63,232        —          164,882      —          —          228,114

Expenditures for Long-Lived Assets

             

Period from May 26, 2010 to June 30, 2010

     15,300        —          5,208      367        —          20,875

Period from January 1, 2010 to May 25, 2010

     43,666        —          18,418      1,703          63,787

For the six months ended June 30, 2009

     44,639        22,367        50,959      1,220        —          119,185

The table below provides a reconciliation of total segment margin to net income (loss) from continuing operations.

 

Page | 25


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

     Successor           Predecessor  
     Period from
Acquisition
(May 26, 2010)
to June 30, 2010
          Period from
April 1, 2010
to Disposition
(May 25, 2010)
    Three Months Ended
June 30, 2009
    Period from
January 1, 2010
to Disposition
(May 25, 2010)
    Six Months Ended
June 30, 2009
 
     (in thousands)           (in thousands)  

Net (loss) income attributable to Regency Energy Partners LP

   $ (4,924        $ (4,740   $ 5,890      $ (5,352   $ 154,279   

Add (deduct):

               

Operation and maintenance

     11,942             21,430        31,974        53,841        68,016   

General and administrative

     7,104             21,809        14,127        37,212        29,205   

Loss (gain) on asset sales, net

     10             19        651        303        (133,280

Depreciation and amortization

     10,995             18,609        26,236        46,084        54,125   

Income from unconsolidated subsidiaries

     (8,121          (7,959     (1,587     (15,872     (1,923

Interest expense, net

     8,109             14,114        19,568        36,459        33,795   

Other income and deductions, net

     3,510             624        (214     3,891        (256

Income tax expense (benefit)

     245             83        (515     404        (416

Net income attributable to the noncontrolling interest

     29             244        65        406        100   
                                             

Total segment margin

   $ 28,899           $ 64,233      $ 96,195      $ 157,376      $ 203,645   
                                             

11. Equity-Based Compensation

The Partnership’s LTIP for its employees, directors and consultants authorizes grants up to 2,865,584 common units. Because control changed from GE EFS to ETE, all then outstanding LTIP, exclusive of the May 7, 2010 phantom unit grant described below, vested during the predecessor period and the Partnership recorded a one-time general and administrative charge of $9,893,000 as a result of the vesting of these units on May 25, 2010. LTIP compensation expense of $137,000, $10,431,000, $12,070,000, $1,561,000 and $2,750,000 is recorded in general and administrative expense in the statement of operations for the periods from May 26, 2010 to June 30, 2010, April 1, 2010 to May 25, 2010 and January 1, 2010 to May 25, 2010, and for the three and six months ended June 30, 2009, respectively.

Common Unit Option and Restricted (Non-Vested) Units.

The common unit options activity for the six months ended June 30, 2010 is as follows.

 

Common Unit Options

   Units     Weighted Average
Exercise Price
   Weighted
Average
Contractual
Term (Years)
   Aggregate
Intrinsic Value
*(in thousands)

Outstanding at the beginning of period

   306,651      $ 21.50      

Granted

   —          —        

Exercised

   (13,500     20.00      

Forfeited or expired

   (3,001     23.73      
              

Outstanding at end of period

   290,150        21.57    5.8    833
              

Exercisable at the end of the period

   290,150            833

 

* Intrinsic value equals the closing market price of a unit less the option strike price, multiplied by the number of unit options outstanding as of the end of the period presented, unit options with an exercise price greater than the end of the period closing market price are excluded.

During the six months ended June 30, 2010, the Partnership received $270,000 in proceeds from the exercise of unit options.

The restricted (non-vested) common unit activity for the six months ended June 30, 2010 is as follows.

 

           Weighted Average Grant Date

Restricted (Non-Vested) Common Units

   Units     Fair Value

Outstanding at the beginning of the period

   464,009      $ 28.36

Granted

   —          —  

Vested

   (444,759     28.19

Forfeited or expired

   (19,250     32.35
        

Outstanding at the end of period

   —          —  
        

Phantom Units. The Partnership’s phantom units are in substance two grants composed of (1) service condition grants with graded vesting over three years; and (2) market condition grants with cliff vesting based upon the Partnership’s relative ranking in total unitholder return among 20 peer companies, as disclosed in Item 11 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009. As control changed from GE EFS to ETE, all outstanding phantom units, exclusive of the May 7, 2010 grant described below, vested. The service condition grants vested at a rate of 100 percent and the market condition grants vested at a rate of 150 percent pursuant to the terms of the award.

 

Page | 26


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The Partnership awarded 247,500 phantom units to senior management and certain key employees on May 7, 2010. These phantom units include a provision that will accelerate vesting (1) upon a change in control and (2) within 12 months of a change in control, if termination without “Cause” (as defined) or resignation for “Good Reason” (as defined) occurs, the phantom units will vest. The Partnership expects to recognize $3,187,000 of compensation expense related to non-vested phantom units over a period of 2.8 years.

The following table presents phantom unit activity for the six months ended June 30, 2010.

 

Phantom Units    Units     Weighted Average  Grant
Date Fair Value

Outstanding at the beginning of the period

   301,700      $ 8.63

Service condition grants

   108,500        20.76

Market condition grants

   148,500        11.89

Vested service condition

   (138,313     13.97

Vested market condition

   (168,420 )*      4.65

Forfeited service condition

   (6,467     19.30

Forfeited market condition

   (10,500     10.20
        

Total outstanding at end of period

   235,000        16.31
        

 

* Upon the change in control, these awards converted into 252,630 common units.

12. Fair Value Measures

The fair value measurement provisions establish a three-tiered fair value hierarchy that prioritizes inputs to valuation techniques used in fair value calculations. The three levels of inputs are defined as follows:

 

   

Level 1 - unadjusted quoted prices for identical assets or liabilities in active accessible markets;

 

   

Level 2 - inputs that are observable in the marketplace other than those classified as Level 1; and

 

   

Level 3 - inputs that are unobservable in the marketplace and significant to the valuation.

Entities are encouraged to maximize the use of observable inputs and minimize the use of unobservable inputs. If a financial instrument uses inputs that fall in different levels of the hierarchy, the instrument will be categorized based upon the lowest level of input that is significant to the fair value calculation.

Derivatives. The Partnership’s financial assets and liabilities measured at fair value on a recurring basis are derivatives related to commodity swaps and embedded derivatives in the Series A Preferred Units. Derivatives related to commodity swaps are valued using discounted cash flow techniques. These techniques incorporate Level 1 and Level 2 inputs such as future interest rates and commodity prices. These market inputs are utilized in the discounted cash flow calculation considering the instrument’s term, notional amount, discount rate and credit risk and are classified as Level 2 in the hierarchy. Derivatives related to Series A Preferred Units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected volatility, and are classified as Level 3 in the hierarchy. The change in fair value of the derivatives related to Series A Preferred Units is recorded in other income and deductions, net within the statement of operations.

The following table presents the Partnership’s derivative assets and liabilities measured at fair value on a recurring basis.

 

    Fair Value Measurement at June 30, 2010   Fair Value Measurement at December 31, 2009
    Fair Value Total   Quoted Prices in
Active Markets
(Level 1)
  Significant
Observable
Inputs
(Level 2)
  Unobservable
Inputs
(Level  3)
  Fair Value Total   Quoted Prices in
Active Markets
(Level 1)
  Significant
Observable
Inputs
(Level 2)
  Unobservable
Inputs
(Level 3)
    (in thousands)

Assets

               

Commodity Derivatives:

               

Natural Gas

  3,125   —     3,125   —     602   —     602   —  

Natural Gas Liquids

  12,222   —     12,222   —     15,484   —     15,484   —  

Condensate

  5,727   —     5,727   —     9,108   —     9,108   —  
                               

Total Assets

  21,074   —     21,074   —     25,194   —     25,194   —  
                               

Liabilities

               

Interest rate swaps

  1,877   —     1,877   —     1,064   —     1,064   —  

Commodity Derivatives:

    —       —       —       —  

Natural Gas

  15   —     15   —     51   —     51   —  

Natural Gas Liquids

  2,025   —     2,025   —     15,034   —     15,034   —  

Condensate

  29   —     29   —     416   —     416   —  

Series A Preferred Units

  52,239   —     —     52,239   44,594   —     —     44,594
                               

Total Liabilities

  56,185   —     3,946   52,239   61,159   —     16,565   44,594
                               

 

Page | 27


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the six months ended June 30, 2010.

 

     Derivatives related to
Series A

Preferred Units
     (in thousands)

Beginning Balance- December 31, 2009

   $ 44,594

Net unrealized losses included in other income and deductions, net

     4,039
      

Ending Balance- May 25, 2010

     48,633

Net unrealized losses included in other income and deductions, net

     3,606
      

Ending Balance- June 30, 2010

   $ 52,239
      

The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. Restricted cash and related escrow payable approximates fair value due to the relatively short-term settlement period of the escrow payable. Long-term debt, other than the senior notes, is comprised of borrowings which incur interest under a floating interest rate structure. Accordingly, the carrying value approximates fair value. The estimated fair values of the senior notes due 2013 and 2016, based on third party market value quotations as of June 30, 2010, were $369,119,000 and $265,000,000, respectively.

13. Subsequent Events

On July 27, 2010, the Partnership declared a distribution of $0.445 per outstanding common unit and Series A Preferred Unit, including units equivalent to the General Partner’s two percent interest in the Partnership, and a distribution with respect to incentive distribution rights of approximately $915,000, payable on August 13, 2010, to unitholders of record at the close of business on August 6, 2010.

On July 15, 2010, the Partnership sold its gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,000,000. The Partnership plans to use the proceeds from the sale of the assets to fund future capital expenditures.

On August 6, 2010, the Partnership agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185,000,000.

 

Page | 28


Item 2. 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 and transportation of natural gas and NGLs. We provide these services through systems located in Louisiana, Texas, Arkansas, Pennsylvania, Mississippi, Alabama, and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma.

RECENT DEVELOPMENTS

HPC Purchase. On April 30, 2010, we purchased 76,989 units representing general partner interests in HPC for an aggregate purchase price of $92,087,000 from EFS Haynesville, an affiliate of GECC and us. This purchase was funded using our revolving credit facility and it increased our ownership percentage in HPC from 43 percent to 49.99 percent. The Partnership and EFS Haynesville also entered into a Voting Agreement which grants the Partnership the right to vote the general partner interest in HPC retained by EFS Haynesville.

ETE Acquisition. On May 26, 2010, GP Seller completed the sale of all of the outstanding membership interests of the General Partner pursuant to a Purchase Agreement (the “Purchase Agreement”) among itself, ETE and ETE GP. Prior to the closing of the transactions under the Purchase Agreement, GP Seller, an affiliate of GE EFS, owned all the outstanding limited partners’ interests in the General Partner, which is the sole general partner of the Partnership, and the entire member’s interest in the Managing General Partner, which is the sole general partner of the General Partner and by virtue of that position controlled us. As a result of this transaction, control of us transferred from GE EFS to ETE. In connection with this transaction, our assets and liabilities were required to be adjusted to fair value on the closing date (May 26, 2010) by application of “push-down” accounting.

MEP Purchase. On May 26, 2010, we, Regency Midcon and ETE entered into the Contribution Agreement, pursuant to which ETE agreed to contribute to the Partnership (through Regency Midcon) 100 percent of the membership interests in ETC III and the option to purchase all of the outstanding membership interests in ETC II (0.1 percent ownership of members’ interest in MEP), that is exercisable one year and one day following the closing. In return, we issued 26,266,791 of our common units, valued at approximately $600,000,000 based on a 10-day volume weighted average closing price of our common units as of May 4, 2010, to ETE in a private placement, relying on Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”). ETE paid $12,848,000 in cash to us as an estimated purchase price adjustment. The consideration is subject to further post-closing adjustment. Following completion of these transactions, we indirectly own 49.9 percent of MEP and have an option to acquire an indirect 0.1 percent interest in MEP (as described above) that is exercisable on May 27, 2011. An affiliate of Kinder Morgan Energy Partners, L.P. continues to own the other 50 percent interest in MEP and acts as the operator of MEP. In June 2010, we made an additional capital contribution of $38,922,000 to MEP.

Services Agreement. On May 26, 2010, we entered into the Services Agreement with ETE and ETE Services Company, LLC (“Services Co.”). Under the Services Agreement, Services Co. will perform certain general and administrative services to be agreed upon by the parties. We will pay Services Co.’s direct expenses for the provision of these services, plus an annual fee of $10,000,000, and we will receive the benefit of any cost savings recognized for these services. The Services Agreement has a five-year term, subject to earlier termination rights in the event of a change of control of a party, the failure to achieve certain costs savings for the benefit of us or upon an event of default.

Logansport Expansion. We completed Phase I and Phase II expansions of the Logansport Gathering System located in the Haynesville Shale in north Louisiana in August. The expansions add an incremental 485 MMcf/d of gathering capacity. The total gathering capacity of the Logansport Gathering System is now approximately 710 MMcf/d.

HPC. On June 24, 2010, the FERC approved a settlement establishing RIG’s maximum rates for NGPA Section 311 transportation services for the period commencing February 1, 2010. Under the settlement, which applies to RIG’s interstate shippers, RIG is not required to make any refunds to shippers, and it is authorized to implement maximum rates that are higher than RIG’s previously effective maximum rates. In addition, RIG was authorized to increase its maximum fuel retention rates upon the installation of additional compression on RIGS. Consistent with FERC policy, RIG is required to justify its current rates or propose new rates on or before February 1, 2015.

On May 20, 2010, the FERC issued Order No. 735, which revises the contract reporting requirements for intrastate natural gas pipelines that provide interstate transportation services pursuant to Section 311 of the NGPA. The order principally modifies the existing annual reporting requirements by requiring expanded information to be filed publicly on a quarterly basis. The new reporting requirements will increase administration costs for RIG and require the disclosure of customer-specific information, including rate information that was previously not public for intrastate pipelines.

 

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Our total project costs for both the Haynesville and Red River Expansion Projects were completed nearly $60,000,000 under budget for a total of approximately $641,000,000.

Gulf States. FERC has initiated an audit of Gulf States’ compliance with certain requirements for the posting of information. FERC routinely conducts such audits of regulated companies, and Gulf States will correct its postings to the extent required.

East Texas. On July 15, 2010, we sold our gathering and processing assets located in east Texas to an affiliate of Tristream Energy LLC for approximately $70,000,000. We plan to use the proceeds from the sale of the assets to fund future capital expenditures.

Zephyr Acquisition. On August 6, 2010, we agreed to acquire Zephyr Gas Services, LLC, a field services company for approximately $185,000,000.

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

 

   

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

 

   

Transportation: We own and operate a 49.99 percent interest in HPC which, through RIGS, delivers natural gas from northwest Louisiana to markets as well as downstream pipelines in northeast Louisiana through a 450 mile intrastate pipeline system. We also own a 49.9 percent in MEP which has a 500 mile natural gas pipeline that extends from the southeast corner of Oklahoma, across northeast Texas, northern Louisiana, central Mississippi and into Alabama.

 

   

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

 

   

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

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

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

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

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

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

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

Adjusted Segment Margin and Adjusted Total Segment Margin. We define adjusted segment margin as segment margin adjusted for non-cash gains (losses) from commodity derivatives. We define adjusted total segment margin as total segment margin adjusted for non-cash gains (losses) from commodity derivatives. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, including intersegment eliminations. Adjusted segment margin and adjusted total segment margin are included as supplemental disclosures because they are primary performance measures used by management as they represent the results of product purchases and sales, a key component of our operations.

 

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Revenue Generating Horsepower. Revenue generating horsepower is the primary driver for revenue growth in our contract compression segment, and it is also the primary measure for evaluating our operational efficiency. Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

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

EBITDA and Adjusted EBITDA. We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. We define adjusted EBITDA as EBITDA plus or minus the following:

 

   

non-cash loss (gain) from commodity and embedded derivatives;

 

   

non-cash unit based compensation;

 

   

loss (gain) on asset sales, net;

 

   

loss on debt refinancing;

 

   

other (income) expense, net, and

 

   

the Partnership’s interest in adjusted EBITDA from unconsolidated subsidiaries less income from unconsolidated subsidiaries.

These measures are used as supplemental measures by our management and by external users of our financial statements such as investors, banks, research analysts and others, to assess:

 

   

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

 

   

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

 

   

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

 

   

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

Neither EBITDA nor adjusted EBITDA should be considered as an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP. EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership. The Partnership added non-cash unit based compensation as a reconciling item from EBITDA to adjusted EBITDA to conform the Partnership’s calculation of adjusted EBITDA with ETE’s. The following table presents a reconciliation of EBITDA and adjusted EBITDA to net cash flows provided by operating activities and to net (loss) income.

 

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     Combined Six Months Ended June 30, 2010        
     Successor     Predecessor              
     Period from Acquisition
(May 26, 2010) to
June 30, 2010
    Period from
January 1, 2010
to May 25, 2010
    Total     Six Months Ended
June 30, 2009
 
     (in thousands)  

Reconciliation of “Adjusted 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

   $ (16,207   $ 89,421      $ 73,214      $ 69,271   

Add (deduct):

        

Depreciation and amortization, including debt issuance cost amortization

     (11,330     (49,363     (60,693     (56,750

Write-off of debt issuance costs

     —          (1,780     (1,780     —     

Income from unconsolidated subsidiaries

     8,121        15,872        23,993        1,923   

Derivative valuation change

     (6,921     (12,004     (18,925     6,293   

(Loss) gain on assets sales, net

     (10     (303     (313     133,280   

Unit based compensation expenses

     (137     (12,070     (12,207     (2,750

Changes in current assets and liabilities

        

Trade accounts receivable, accrued revenues and related party receivables

     (13,843     11,272        (2,571     (38,073

Other current assets

     (585     (2,516     (3,101     (3,728

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

     15,460        (8,649     6,811        39,185   

Other current liabilities

     20,497        (22,614     (2,117     7,396   

Distribution less than earnings of unconsolidated subsidiaries, net

     —          (12,446     (12,446     (1,900

Other assets and liabilities

     60        234        294        232   
                                

Net (loss) income

     (4,895     (4,946     (9,841     154,379   
                                

Add (deduct):

        

Interest expense, net

     8,109        36,459        44,568        33,795   

Depreciation and amortization

     10,995        46,084        57,079        54,125   

Income tax expense (benefit)

     245        404        649        (416
                                

EBITDA

     14,454        78,001        92,455        241,883   
                                

Add (deduct):

        

Non-cash loss (gain) from commodity and embedded derivatives

     5,856        11,189        17,045        (6,293

Non-cash unit based compensation

     113        11,925        12,038        2,623   

Loss (gain) on assets sales, net

     10        303        313        (133,280

Income from unconsolidated subsidiaries

     (8,121     (15,872     (23,993     (1,923

Partnership’s ownership interest in HPC’s adjusted EBITDA

     5,824        21,184        27,008        3,871   

Partnership’s ownership interest in MEP’s adjusted EBITDA