Form 10-Q

 

 

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 March 31, 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 93,191,602 common units outstanding as of April 30, 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

El Paso

   El Paso Field Services, LP

FASB

   Financial Accounting Standards Board

FERC

   Federal Energy Regulatory Commission

Finance Corp.

   Regency Energy Finance Corp., a wholly-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

HPC

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

LIBOR

   London Interbank Offered Rate

LTIP

   Long-Term Incentive Plan

MMbtu/d

   One million BTUs per day

MMcf

   One million cubic feet

MMcf/d

   One million cubic feet per day

NYMEX

   New York Mercantile Exchange

Partnership

   Regency Energy Partners LP

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

TCEQ

   Texas Commission on Environmental Quality

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 system and our customers;

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

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

 

   

weather and other natural phenomena;

 

   

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

 

   

regulation of transportation rates on our natural gas pipelines;

 

   

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

 

   

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

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

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


Regency Energy Partners LP

Condensed Consolidated Balance Sheets

(in thousands except unit data)

 

     March 31,
2010
    December 31,
2009
 
     (unaudited)        
ASSETS     

Current Assets:

    

Cash and cash equivalents

   $ 4,086      $ 9,827   

Restricted cash

     1,511        1,511   

Trade accounts receivable, net of allowance of $435 and $1,130

     24,655        30,433   

Accrued revenues

     96,584        95,240   

Related party receivables

     3,416        6,222   

Derivative assets

     22,708        24,987   

Other current assets

     9,930        10,556   
                

Total current assets

     162,890        178,776   

Property, Plant and Equipment:

    

Gathering and transmission systems

     470,275        465,959   

Compression equipment

     835,037        823,060   

Gas plants and buildings

     159,795        159,596   

Other property, plant and equipment

     167,562        162,433   

Construction-in-progress

     104,071        95,547   
                

Total property, plant and equipment

     1,736,740        1,706,595   

Less accumulated depreciation

     (272,104     (250,160
                

Property, plant and equipment, net

     1,464,636        1,456,435   

Other Assets:

    

Investment in unconsolidated subsidiary

     477,717        453,120   

Long-term derivative assets

     799        207   

Other, net of accumulated amortization of debt issuance costs of $4,631 and $10,743

     35,294        19,468   
                

Total other assets

     513,810        472,795   

Intangible Assets and Goodwill:

    

Intangible assets, net of accumulated amortization of $37,126 and $33,929

     194,097        197,294   

Goodwill

     228,114        228,114   
                

Total intangible assets and goodwill

     422,211        425,408   
                

TOTAL ASSETS

   $ 2,563,547      $ 2,533,414   
                
LIABILITIES & PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST     

Current Liabilities:

    

Trade accounts payable

   $ 36,161      $ 44,912   

Accrued cost of gas and liquids

     73,233        76,657   

Related party payables

     927        2,312   

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

     10,795        11,292   

Derivative liabilities

     5,317        12,256   

Escrow payable

     1,511        1,511   

Other current liabilities

     24,499        12,368   
                

Total current liabilities

     152,443        161,308   

Long-term derivative liabilities

     48,843        48,903   

Other long-term liabilities

     14,546        14,183   

Long-term debt, net

     1,083,665        1,014,299   

Commitments and contingencies

    

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

     51,766        51,711   

Partners’ Capital and Noncontrolling Interest:

    

Common units (94,271,956 and 94,243,886 units authorized; 93,197,173 and 93,188,353 units issued and outstanding at March 31, 2010 and December 31, 2009)

     1,170,270        1,211,605   

General partner interest

     18,337        19,249   

Accumulated other comprehensive gain (loss)

     10,500        (1,994

Noncontrolling interest

     13,177        14,150   
                

Total partners’ capital and noncontrolling interest

     1,212,284        1,243,010   
                

TOTAL LIABILITIES AND PARTNERS’ CAPITAL AND NONCONTROLLING INTEREST

   $ 2,563,547      $ 2,533,414   
                

See accompanying notes to condensed consolidated financial statements

 

Page | 4


Regency Energy Partners LP

Condensed Consolidated Statements of Operations

Unaudited

(in thousands except unit data and per unit data)

 

     Three Months Ended March 31,  
     2010     2009  

REVENUES

    

Gas sales

   $ 142,893      $ 148,270   

NGL sales

     97,329        49,585   

Gathering, transportation and other fees, including related party amounts of $8,520 and $811

     70,328        72,621   

Net realized and unrealized (loss) gain from derivatives

     (939     14,455   

Other

     8,141        5,194   
                

Total revenues

     317,752        290,125   

OPERATING COSTS AND EXPENSES

    

Cost of sales, including related party amounts of $3,366 and $247

     224,609        182,901   

Operation and maintenance

     32,411        36,042   

General and administrative

     15,403        14,852   

Loss (gain) on asset sales, net

     284        (133,932

Depreciation and amortization

     27,475        27,889   
                

Total operating costs and expenses

     300,182        127,752   

OPERATING INCOME

     17,570        162,373   

Income from unconsolidated subsidiary

     7,913        336   

Interest expense, net

     (22,345     (14,227

Other income and deductions, net

     (3,267     42   
                

(LOSS) INCOME BEFORE INCOME TAXES

     (129     148,524   

Income tax expense

     321        100   
                

NET (LOSS) INCOME

     (450     148,424   

Net income attributable to noncontrolling interest

     (162     (35
                

NET (LOSS) INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP

   $ (612   $ 148,389   
                

Amounts attributable to Series A convertible redeemable preferred units

     2,001        —     

General partner’s interest, including IDR

     662        3,533   

Amount allocated to non-vested common units

     (79     1,354   

Beneficial conversion feature for Class D common units

     —          820   
                

Limited partners’ interest

   $ (3,196   $ 142,682   
                

Basic and Diluted (loss) earnings per unit:

    

Amount allocated to common units

   $ (3,196   $ 142,682   

Weighted average number of common units outstanding

     92,761,787        77,271,886   

Basic (loss) income per common unit

   $ (0.03   $ 1.85   

Diluted (loss) income per common unit

   $ (0.03   $ 1.78   

Distributions paid per unit

   $ 0.445      $ 0.445   

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

   $ —        $ —     

See accompanying notes to condensed consolidated financial statements

 

Page | 5


Regency Energy Partners LP

Condensed Consolidated Statements of Comprehensive Income

Unaudited

(in thousands)

 

     Three Months Ended March 31,  
     2010     2009  

Net (loss) income

   $ (450   $ 148,424   

Net hedging amounts reclassified to earnings

     2,657        (14,250

Net change in fair value of cash flow hedges

     9,837        5,380   
                

Comprehensive income

   $ 12,044      $ 139,554   

Comprehensive income attributable to noncontrolling interest

     162        35   
                

Comprehensive income attributable to Regency Energy Partners LP

   $ 11,882      $ 139,519   
                

See accompanying notes to condensed consolidated financial statements

 

Page | 6


Regency Energy Partners LP

Condensed Consolidated Statements of Cash Flows

Unaudited

(in thousands)

 

     Three Months Ended March 31,  
     2010     2009  

OPERATING ACTIVITIES

    

Net (loss) income

   $ (450   $ 148,424   

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

    

Depreciation and amortization, including debt issuance cost amortization

     29,389        28,932   

Write-off of debt issuance costs

     1,780        —     

Income from unconsolidated subsidiary

     (7,913     (336

Derivative valuation changes

     7,182        (3,565

Loss (gain) on asset sales, net

     284        (133,932

Unit-based compensation expenses

     1,639        1,189   

Cash flow changes in current assets and liabilities:

    

Trade accounts receivable, accrued revenues, and related party receivables

     (2,017     22,741   

Other current assets

     1,091        10,458   

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

     (13,826     (36,948

Other current liabilities

     12,131        (1,022

Distribution received from unconsolidated subsidiary

     3,526        —     

Other assets and liabilities

     (35     390   
                

Net cash flows provided by operating activities

     32,781        36,331   
                

INVESTING ACTIVITIES

    

Capital expenditures

     (38,465     (80,255

Capital contribution to unconsolidated subsidiary

     (20,210     —     

Proceeds from asset sales

     10,632        83,097   
                

Net cash flows (used in) provided by investing activities

     (48,043     2,842   
                

FINANCING ACTIVITIES

    

Net borrowings under revolving credit facility

     69,009        7,004   

Debt issuance costs

     (15,272     (6,055

Partner distributions

     (43,034     (34,143

Distributions to noncontrolling interest

     (1,135     —     

Equity issuance costs

     (47     —     
                

Net cash flows provided by (used in) financing activities

     9,521        (33,194
                

Net (decrease) increase in cash and cash equivalents

     (5,741     5,979   

Cash and cash equivalents at beginning of period

     9,827        599   
                

Cash and cash equivalents at end of period

   $ 4,086      $ 6,578   
                

Supplemental cash flow information:

    

Non-cash capital expenditures

   $ 9,936      $ 18,241   

Contribution of fixed assets, intangible assets, goodwill and working capital to HPC

     —          263,921   

See accompanying notes to condensed consolidated financial statements

 

Page | 7


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  

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

   8,820      —          —          —          —          —     

Issuance of common units, net of costs

   —        (47     —          —          —          (47

Unit-based compensation expenses

   —        1,639        —          —          —          1,639   

Accrued distributions to phantom units

   —        (138     —          —          —          (138

Partner distributions

   —        (41,460     (1,574     —          —          (43,034

Distributions to noncontrolling interest

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

Net (loss) income

   —        (1,274     662        —          162        (450

Accretion of Series A convertible redeemable preferred units

   —        (55     —          —          —          (55

Net cash flow hedge amounts reclassified to earnings

   —        —          —          2,657        —          2,657   

Net change in fair value of cash flow hedges

   —        —          —          9,837        —          9,837   
                                             

Balance - March 31, 2010

   93,197,173    $ 1,170,270      $ 18,337      $ 10,500      $ 13,177      $ 1,212,284   
                                             

See accompanying notes to condensed consolidated financial statements

 

Page | 8


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.

The unaudited financial information as of, and for the three months ended March 31, 2010, 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 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.

 

     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

     (1,994     (490     (585     (128     (3,197
                                        

Balance at March 31, 2010

   $ 124,338      $ 34,872      $ 29,923      $ 4,964      $ 194,097   
                                        

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)

   $ 9,589

2011

     11,477

2012

     11,235

2013

     11,235

2014

     11,235

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. 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 will 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 available to the general partner and limited partner interests.

 

Page | 9


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The following table provides a reconciliation of the numerator and denominator of the basic and diluted earnings per common unit computations for the three months ended March 31, 2010 and 2009.

 

     For the Three Months Ended March 31, 2010     For the Three Months Ended March 31, 2009
     Loss
(Numerator)
    Units
(Denominator)
   Per-Unit
Amount
    Income
(Numerator)
   Units
(Denominator)
   Per-Unit
Amount
     (in thousands except unit and per unit data)

Basic Earnings per Unit

               

Limited partners’ interest

   $ (3,196   92,761,787    $ (0.03   $ 142,682    77,271,886    $ 1.85

Effect of Dilutive Securities

               

Class D common units

     —        —          820    3,234,003   
                             

Diluted Earnings per Unit

   $ (3,196   92,761,787    $ (0.03   $ 143,502    80,505,889    $ 1.78
                             

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.

 

     Three Months Ended March 31,
     2010    2009

Non-vested common units

   421,072    699,175

Phantom units*

   383,706    —  

Common unit options

   306,651    328,618

Series A Preferred Units

   4,371,586    —  

 

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

3. Investment in Unconsolidated Subsidiary

HPC was established in March 2009 and as of March 31, 2010, the Partnership owns a 43 percent partner’s interest in HPC. In February 2010, the Partnership made an additional capital contribution of $20,210,000 to HPC. The Partnership recognized $7,913,000 and $336,000 during the quarters ended March 31, 2010 and 2009, respectively, in income from unconsolidated subsidiary for its ownership interest. In addition, the Partnership received $3,526,000 of distributions during the quarter ended March 31, 2010. The summarized financial information of HPC is disclosed below.

RIGS Haynesville Partnership Co.

Condensed Consolidated Balance Sheets

(in thousands)

 

      March 31, 2010    December 31, 2009
     (Unaudited)     
ASSETS      

Total current assets

   $ 44,033    $ 39,239

Restricted cash, non-current

     55,610      33,595

Property, plant and equipment, net

     884,774      861,570

Total other assets

     149,324      149,755
             

TOTAL ASSETS

   $ 1,133,741    $ 1,084,159
             
LIABILITIES & PARTNERS’ CAPITAL      

Total current liabilities

   $ 19,346    $ 30,967

Long-term debt

     4,000      —  

Partners’ capital

     1,110,395      1,053,192
             

TOTAL LIABILITIES & PARTNERS’ CAPITAL

   $ 1,133,741    $ 1,084,159
             

 

Page | 10


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

RIGS Haynesville Partnership Co.

Condensed Consolidated Income Statements

(in thousands)

 

     For the Three Months Ended
     March 31, 2010     March 31, 2009
     (Unaudited)

Total revenues

   $ 35,189      $ 1,826

Total operating costs and expenses

     16,723        1,046
              

OPERATING INCOME

     18,466        780

Interest expense

     (102     —  

Other income and deductions, net

     39        104
              

NET INCOME

   $ 18,403      $ 884
              

4. 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. It is the Partnership’s policy not to take any speculative positions with its derivative contracts.

On April 5, 2010, the Partnership entered into additional NGLs swaps to hedge a portion of its 2011 NGLs sales.

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 for below.

 

     As of March 31, 2010     As of April 5, 2010  
     2010     2011     2010     2011  

NGLs

   73   29   73   41

Condensate

   84   50   84   50

Natural gas

   74   23   74   23

At March 31, 2010, the 2010 and 2011 natural gas and condensate swaps are accounted for as cash flow hedges with the exception of one month of the 2010 condensate swaps, which is accounted for using the mark-to-market accounting; the 2010 NGLs swaps are accounted for using a combination of cash flow hedge and mark-to-market accounting and the 2011 NGLs swaps are accounted for as cash flow hedges.

Interest Rate Risk. The Partnership is exposed to variable interest rate risk as a result of borrowings under its credit facility. As of March 31, 2010, the Partnership had $488,650,000 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 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

 

Page | 11


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

contract 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 $23,596,000, which would be reduced by $6,181,000 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. During the three months ended March 31, 2010, the loss recognized related to these embedded derivatives was $3,385,000 and was reflected in other income and deductions, net on the condensed consolidated statement of operations.

Quantitative Disclosures. The Partnership expects to reclassify $5,973,000 of net hedging gains to revenues from accumulated other comprehensive income (“OCI”) in the next 12 months.

The Partnership’s derivative assets and liabilities, including credit risk adjustment, as of March 31, 2010 and December 31, 2009 and for the three months ended March 31, 2010 and 2009 are detailed below.

 

     Assets     Liabilities  
     March 31, 2010     December 31, 2009     March 31, 2010    December 31, 2009  
     (in thousands)  

Derivatives designated as cash flow hedges

         

Current amounts

         

Interest rate contracts

   $ —        $ —        $ —      $ 1,067   

Commodity contracts

     10,909        9,525        5,282      11,200   

Long-term amounts

         

Commodity contracts

     799        207        864      931   
                               

Total cash flow hedging instruments

     11,708        9,732        6,146      13,198   
                               

Derivatives not designated as cash flow hedges

         

Current amounts

         

Commodity contracts

     11,888        15,514        35      31   

Long-term amounts

         

Commodity contracts

     —          —          —        3,378   

Embedded derivatives in Series A Preferred Units

     —          —          47,979      44,594   
                               

Total derivatives not designated as cash flow hedges

     11,888        15,514        48,014      48,003   
                               

Credit Risk Assessment

         

Current amounts

     (89     (52     —        (42
                               

Total derivatives

   $ 23,507      $ 25,194      $ 54,160    $ 61,159   
                               

Derivatives designated as cash flow hedges

 

     Three Months Ended March 31, 2010     Three Months Ended March 31, 2009  
     Interest
Rate
    Commodity     Total     Interest
Rate
    Commodity     Total  
     (in thousands)  

Gain (loss) recorded in accumulated OCI (Effective)

   $ —        $ 6,943      $ 6,943      $ (838   $ 6,218      $ 5,380   

Gain (loss) reclassified from accumulated OCI into income (Effective)*

     (1,060     (4,491     (5,551     (1,472     16,519        15,047   

(Loss) gain recognized in income (Ineffective)*

     —          (498     (498     —          615        615   
Derivatives not designated as cash flow hedges             
     Three Months Ended March 31, 2010     Three Months Ended March 31, 2009  
     Embedded
Derivative
    Commodity     Total     Embedded
Derivative
    Commodity     Total  
     (in thousands)  

Gain (loss) from dedesignation amortized from accumulated OCI into income*

   $ —        $ 2,894      $ 2,894      $ —        $ (797   $ (797

Gain (loss) gain recognized in income*

     (3,385     1,235        (2,150     —          (1,402     (1,402

Credit risk assessment for commodity and interest rate swaps

  

     Three Months Ended March 31,  
     2010     2009  
     (in thousands)  

Loss recognized in income*

   $ (79   $ (480

 

* Gain and loss related to commodity swaps, interest rate swaps and embedded derivatives were included in revenues, interest expense, and other income and deductions, net, respectively, in the Partnership’s condensed consolidated statements of operations for the three months ended March 31, 2010 and 2009.

 

Page | 12


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

5. Long-term Debt

Obligations in the form of senior notes and borrowings under the credit facility are as follows.

 

     March 31, 2010     December 31, 2009  
     (in thousands)  

Senior notes

   $ 595,015      $ 594,657   

Revolving loans

     488,650        419,642   
                

Total

     1,083,665        1,014,299   

Less: current portion

     —          —     
                

Long-term debt

   $ 1,083,665      $ 1,014,299   

Availability under revolving credit facility:

    

Total credit facility limit

   $ 900,000      $ 900,000   

Unfunded commitments

     —          (10,675

Revolving loans

     (488,650     (419,642

Letters of credit

     (10,757     (16,257
                

Total available

   $ 400,593      $ 453,426   
                

Long-term debt maturities as of March 31, 2010 for each of the next five years are as follows:

 

Year Ending December 31,

   Amount  
     (in thousands)  

2010

   $ —     

2011

     —     

2012

     —     

2013

     357,500   

2014

     488,650   

Thereafter

     250,000
        

Total

   $ 1,096,150   
        

 

* As of March 31, 2010, the carrying value of the senior notes due 2016 was $237,515,000 which included an unamortized discount of $12,485,000.

The outstanding balance of revolving debt under the 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 7.80 percent and 5.19 percent for the three months ended March 31, 2010 and 2009, respectively.

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 March 31, 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.

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:

 

   

The 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 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;

 

Page | 13


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

   

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 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 March 31, 2010, the Partnership was in compliance with all of the financial covenants contained within the new credit agreement.

The Partnership treated the amendment of the credit facility as a modification of an existing revolving credit agreement and, therefore, recorded a write-off of debt issuance costs of $1,780,000 that was recorded to interest expense, net in the three months ended March 31, 2010. In addition, the Partnership paid and capitalized $15,272,000 loan fees which will be amortized over the remaining term of the credit facility.

6. 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 March 31, 2010, $1,511,000 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. Discovery ended in October 2009. Trial commenced on April 26, 2010.

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

 

Page | 14


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

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. RFS is seeking assignment of indemnity rights against Tronox from El Paso.

7. 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 will 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.

The following table provides a reconciliation of the beginning and ending balances of the Series A Preferred Units for the three months ended March 31, 2010.

 

     For the Three Months Ended March 31, 2010  
     Units    Amount
(in  thousands)
 

Beginning balance as of January 1, 2010

   4,371,586    $ 51,711   

Accretion to redemption value

   —        55   
             

Ending balance as of March 31, 2010

   4,371,586    $ 51,766
             

 

* This amount will be accreted to $80,000,000 plus any accrued and unpaid distributions by deducting amounts from partners’ capital over the 19.5 remaining years.

8. 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 $20,732,000, and $7,808,000, were recorded in the Partnership’s financial statements during the three months ended March 31, 2010 and 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 $13,127,000 and $9,578,000 during the three months ended March 31, 2010 and 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 period ended March 31, 2010 and 2009, the related party general and administrative expenses reimbursed to the Partnership were $4,133,000 and $226,000, respectively.

Additionally, the Partnership’s contract compression segment provides contract compression services to HPC. HPC also provides transportation service to the Partnership. At March 31, 2010 and for the three months then ended, the Partnership’s related party receivables, related party payables, related party revenues and related party cost of sales were primarily a result of the transactions with HPC described above. Additionally, for the three months ended March 31, 2010, the Partnership sold $195,000 in compression assets to HPC.

9. 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.

 

Page | 15


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The transportation segment consists exclusively of the Partnership’s 43 percent interest in HPC, for which equity method accounting applies. 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 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.

 

Page | 16


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

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

           

For the three months ended March 31, 2010

  $ 276,842      $ —     $ 34,979   $ 5,931      $ —        $ 317,752

For the three months ended March 31, 2009

    243,527        7,544     38,488     566        —          290,125

Intersegment Revenues

           

For the three months ended March 31, 2010

    —          —       5,332     39        (5,371     —  

For the three months ended March 31, 2009

    (2,010     5,064     810     105        (3,969     —  

Cost of Sales

           

For the three months ended March 31, 2010

    222,134        —       3,281     (767     (39     224,609

For the three months ended March 31, 2009

    182,842        1,054     2,317     (153     (3,159     182,901

Segment Margin

           

For the three months ended March 31, 2010

    54,708        —       37,030     6,737        (5,332     93,143

For the three months ended March 31, 2009

    58,675        11,554     36,981     824        (810     107,224

Operation and Maintenance

           

For the three months ended March 31, 2010

    23,761        —       13,778     201        (5,329     32,411

For the three months ended March 31, 2009

    22,306        2,286     12,540     313        (1,403     36,042

Depreciation and Amortization

           

For the three months ended March 31, 2010

    17,289        —       9,207     979        —          27,475

For the three months ended March 31, 2009

    16,721        2,448     8,027     693        —          27,889

Income from Unconsolidated Subsidiary

           

For the three months ended March 31, 2010

    —          7,913     —       —          —          7,913

For the three months ended March 31, 2009

    —          336     —       —          —          336

Assets

           

March 31, 2010

    1,089,360        477,717     917,753     78,717        —          2,563,547

December 31, 2009

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

Investment in Unconsolidated Subsidiary

           

March 31, 2010

    —          477,717     —       —          —          477,717

December 31, 2009

    —          453,120     —       —          —          453,120

Goodwill

           

March 31, 2010

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

December 31, 2009

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

Expenditures for Long-Lived Assets

           

For the three months ended March 31, 2010

    24,000        20,210     11,991     2,474        —          58,675

For the three months ended March 31, 2009

    23,804        22,367     34,032     52        —          80,255

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

 

     Three Months Ended March 31,  
     2010     2009  
     (in thousands)  

Net (loss) income attributable to Regency Energy Partners LP

   $ (612   $ 148,389   

Add (deduct):

    

Operation and maintenance

     32,411        36,042   

General and administrative

     15,403        14,852   

Loss (gain) on asset sales, net

     284        (133,932

Depreciation and amortization

     27,475        27,889   

Income from unconsolidated subsidiary

     (7,913     (336

Interest expense, net

     22,345        14,227   

Other income and deductions, net

     3,267        (42

Income tax expense

     321        100   

Net income attributable to the noncontrolling interest

     162        35   
                

Total segment margin

   $ 93,143      $ 107,224   
                

10. Equity-Based Compensation

Common Unit Option and Restricted (Non-Vested) Units. The Partnership’s LTIP for the Partnership’s employees, directors and consultants covers an aggregate of 2,865,584 common units. Restricted (non-vested) awards generally vest on the basis of one-fourth of the award each year. All outstanding options have vested and expire ten years after the grant date. LTIP compensation expense of $1,376,000 is recorded in general and administrative in the statement of operations for the three months ended March 31, 2010.

 

Page | 17


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The common unit options activity for the three months ended March 31, 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

   —        —        

Forfeited or expired

   —        —        
             

Outstanding at end of period

   306,651      21.50    6.1      380
             

Exercisable at the end of the period

   306,651            380

 

* 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.

The Partnership will make distributions to non-vested restricted common units at the same rate and on the same dates as the common units. Restricted common units are subject to contractual restrictions against transfer which lapse over time; non-vested restricted units are subject to forfeitures on termination of employment. The Partnership expects to recognize $8,344,000 of compensation expense related to the grants of restricted common units under LTIP primarily over the next 1.66 years.

The restricted (non-vested) common unit activity for the three months ended March 31, 2010 is as follows.

 

Restricted (Non-Vested) Common Units

   Units     Weighted Average Grant Date
Fair Value

Outstanding at the beginning of the period

   464,009      $ 28.36

Granted

   —          —  

Vested

   (45,500     28.76

Forfeited or expired

   (19,250     32.35
        

Outstanding at the end of period

   399,259        28.12
        

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. At the end of the measurement period (March 15, 2012) for the market condition grants, the phantom units will convert to common units in a ratio ranging from 0 to 150 percent. For both the service condition grants and the market condition grants, distributions will be accumulated and paid upon vesting.

During the three months ended March 31, 2010, the Partnership awarded 8,500 phantom units to senior management and certain key employees. The Partnership expects to recognize $1,677,000 of compensation expense related to non-vested phantom units over a period of 2.2 years. During the three months ended March 31, 2010, the Partnership recognized $263,000 of expense, which was reflected in general and administrative expense in the statement of operations.

 

Page | 18


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

The following table presents phantom unit activity for the three months ended March 31, 2010.

 

Phantom Units

   Units     Weighted Average Grant
Date Fair Value

Outstanding at the beginning of the period

   301,700      $ 8.63

Service condition grants

   8,500        21.81

Market condition grants

   —          —  

Vested service condition

   (39,598     13.13

Vested market condition

   —          —  

Forfeited service condition

   (1,067     12.46

Forfeited market condition

   (2,400     4.49
        

Total outstanding at end of period

   267,135        10.38
        

11. 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.

 

     March 31, 2010    December 31, 2009
     Assets    Liabilities    Assets    Liabilities
     (in thousands)

Level 1

   $ —      $ —      $ —      $ —  

Level 2

     23,507      6,181      25,194      16,565

Level 3

     —        47,979      —        44,594
                           

Total

   $ 23,507    $ 54,160    $ 25,194    $ 61,159
                           

The following table presents the changes in Level 3 derivatives measured on a recurring basis for the three months ended March 31, 2010.

 

     Derivatives related to
Series A Preferred Units
     March 31, 2010
     (in thousands)

Beginning Balance

   $ 44,594

Net unrealized losses included in other income and deductions, net

     3,385
      

Ending Balance

   $ 47,979
      

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 value of the senior notes due 2013 and 2016, based on third party market value quotations as of March 31, 2010, were $367,331,000 and $265,000,000, respectively.

 

Page | 19


Regency Energy Partners LP

Notes to Unaudited Condensed Consolidated Financial Statements—(Continued)

 

12. Subsequent Events

On April 26, 2010, the Partnership declared a distribution of $0.445 per outstanding common 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 $713,000, payable on May 14, 2010, to unitholders of record at the close of business on May 7, 2010.

On April 30, 2010, the Partnership 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 the Partnership. This purchase was funded using the Partnership’s revolving credit facility and it increased the Partnership’s ownership percentage in HPC from 43 percent to approximately 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 previously retained by EFS Haynesville. Because this transaction occurred between two entities that are under common control, partners’ capital will be reduced by a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount during the second quarter of 2010.

 

Page | 20


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 and the mid-continent region of the United States, which includes Kansas, Colorado, and Oklahoma.

RECENT DEVELOPMENTS

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 approximately 49.99 percent. We and EFS Haynesville also entered into a Voting Agreement which grants us the right to vote the general partner interest in HPC previously retained by EFS Haynesville. Because this transaction occurred between two entities that are under common control, our partners’ capital will be reduced by a deemed distribution of the excess purchase price over EFS Haynesville’s carrying amount during the second quarter of 2010.

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

 

   

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

 

   

Corporate and Others: We own and operate an interstate pipeline that consists of 10 miles of pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana. This pipeline has a FERC 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 an unconsolidated subsidiary.

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.

 

Page | 21


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.

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,

 

   

loss (gain) on asset sales, net,

 

   

loss on debt refinancing,

 

   

other (income) expense, net, and

 

   

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

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

 

   

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

 

   

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

 

   

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

 

   

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

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

 

Page | 22


     Three Months Ended March 31,  
     2010     2009  
     (in thousands)  

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

    

Net cash flows provided by operating activities

   $ 32,781      $ 36,331   

Add (deduct):

    

Depreciation and amortization, including debt issuance cost amortization

     (29,389     (28,932

Write-off of debt issuance costs

     (1,780     —     

Income from unconsolidated subsidiary

     7,913        336   

Derivative valuation change

     (7,182     3,565   

(Loss) gain on assets sales, net

     (284     133,932   

Unit based compensation expenses

     (1,639     (1,189

Changes in current assets and liabilities

    

Trade accounts receivable, accrued revenues and related party receivables

     2,017        (22,741

Other current assets

     (1,091     (10,458

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

     13,826        36,948   

Other current liabilities

     (12,131     1,022   

Distribution received from unconsolidated subsidiary

     (3,526     —     

Other assets and liabilities

     35        (390
                

Net (loss) income

     (450     148,424   
                

Add (deduct):

    

Interest expense, net

     22,345        14,227   

Depreciation and amortization

     27,475        27,889   

Income tax expense

     321        100   
                

EBITDA

     49,691        190,640   
                

Add (deduct):

    

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

     7,191        (3,565

Loss (gain) on assets sales, net

     284        (133,932

Income from unconsolidated subsidiary

     (7,913     (336

Partnership’s ownership interest in HPC’s adjusted EBITDA

     10,675        590   

Other expense, net

     90        729   
                

Adjusted EBITDA

   $ 60,018      $ 54,126   
                

The following table presents a reconciliation of adjusted total segment margin to net (loss) income.

 

     Three Months Ended March 31,  
     2010     2009  
     (in thousands)  

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

    

Net (loss) income

   $ (450   $ 148,424   

Add (deduct):

    

Operation and maintenance

     32,411        36,042   

General and administrative

     15,403        14,852   

Loss (gain) on assets sales, net

     284        (133,932

Depreciation and amortization

     27,475        27,889   

Income from unconsolidated subsidiary

     (7,913     (336

Interest expense, net

     22,345        14,227   

Other income and deductions, net

     3,267        (42

Income tax expense

     321        100   
                

Total segment margin

     93,143        107,224   
                

Add (deduct):

    

Non-cash loss (gain) from commodity derivatives

     3,806        (3,565
                

Adjusted total segment margin

   $ 96,949      $ 103,659   
                

Cash Distributions. On April 26, 2010, the Partnership declared a distribution of $0.445 per outstanding common 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 $713,000, payable on May 14, 2010, to unitholders of record at the close of business on May 7, 2010.

In addition, the Partnership will make a distribution of $0.445 per outstanding Series A Preferred Units, payable on May 14, 2010, to outstanding unitholders at the close of business on May 7, 2010.

 

Page | 23


RESULTS OF OPERATIONS

Partnership

Three Months Ended March 31, 2010 vs. Three Months Ended March 31, 2009

 

     Three Months Ended March 31,              
     2010     2009     Change     Percent  
     (in thousands except percentages and volume data)        

Total revenues

   $ 317,752      $ 290,125      $ 27,627      10

Cost of sales

     224,609        182,901        41,708      23   
                          

Total segment margin (1)

     93,143        107,224        (14,081   13   

Operation and maintenance

     32,411        36,042        (3,631   10   

General and administrative

     15,403        14,852        551      4   

(Gain) loss on asset sales, net

     284        (133,932     134,216      100   

Depreciation and amortization

     27,475        27,889        (414   1   
                          

Operating income

     17,570        162,373        (144,803   89   

Income from unconsolidated subsidiary

     7,913        336        7,577      2,255   

Interest expense, net

     (22,345     (14,227     (8,118   57   

Other income and deductions, net

     (3,267     42        (3,309   7,879   
                          

(Loss) income before income taxes

     (129     148,524        (148,653   100   

Income tax expense

     321        100        221      221   
                          

Net (loss) income

     (450     148,424        (148,874   100   

Net income attributable to the noncontrolling interest

     (162     (35     (127   363   
                          

Net (loss) income attributable to Regency Energy Partners LP

   $ (612   $ 148,389      $ (149,001   100 
                          

Gathering and processing segment margin

   $ 54,708      $ 58,675      $ (3,967   7

Add (deduct):

        

Non-cash gain (loss) from commodity derivatives

     3,806        (3,565     7,371      207   
                          

Adjusted gathering and processing segment margin

     58,514        55,110        3,404      6   

Transportation segment margin

     —          11,554        (11,554   100   

Contract compression segment margin

     37,030        36,981        49      —     

Corporate and others segment margin

     6,737        824        5,913      718   

Inter-segment eliminations

     (5,332     (810     (4,522   558   
                          

Adjusted total segment margin

   $ 96,949      $ 103,659      $ (6,710   6
                          

System inlet volumes (MMBtu/d) (2)

     1,723,844        1,618,342        105,502      7

 

(1) For a reconciliation of segment margin to the most directly comparable financial measure calculated and presented in accordance with GAAP, please read “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
(2) System inlet volumes include total volumes taken into our gathering and processing and transportation systems.

 

Page | 24


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

 

     Three Months Ended March 31,             
     2010    2009    Change     Percent  
     (in thousands except percentages and volume data)        

Gathering and Processing Segment

          

Financial data:

          

Adjusted segment margin (1)

   $ 58,514    $ 55,110    $ 3,404     

Operation and maintenance (2)

     23,761      22,306      1,455      7   

Operating data:

          

Throughput (MMBtu/d) (3)

     1,029,146      1,038,707      (9,561   1   

NGL gross production (Bbls/d)

     25,742      22,721      3,021      13   

Transportation Segment

          

Financial data:

          

Adjusted segment margin (1)

   $ —      $ 11,554    $ (11,554   100 

Operation and maintenance (2)

     —        2,286      (2,286   100   

Operating data:

          

Throughput (MMBtu/d) (3)

     —        812,332      (812,332   100   

Contract Compression

          

Financial data:

          

Segment margin (1)

   $ 37,030    $ 36,981    $ 49      0

Operation and maintenance (2)

     13,778      12,540      1,238      10   

Operating data:

          

Revenue generating horsepower (4)

     759,704      789,494      (29,790   4

Average horsepower per revenue generating compression unit

     858      858      —        —     

Corporate and Others

          

Financial data:

          

Segment margin (1)

   $ 6,737    $ 824    $ 5,913      718 

Operation and maintenance (2)

     201      313      (112   36   

 

(1) Combined adjusted segment margin for our segments differs from consolidated adjusted total segment margin due to intersegment eliminations.
(2) Combined operation and maintenance expense varies from consolidated operation and maintenance expense due to intersegment eliminations.
(3) Combined throughput volumes for the gathering and processing and transportation segments vary from consolidated system inlet volumes due to intersegment eliminations.
(4) Revenue generating horsepower is our total available horsepower less horsepower under contract that is not generating revenue and idle horsepower.

In addition to the revenue generating horsepower and compression units owned and operated by the Contract Compression segment disclosed below, the Contract Compression segment operates 139,961 horsepower owned by the gathering and processing segment as of March 31, 2010. The Contract Compression segment also operates 37,985 horsepower owned by HPC as of March 31, 2010.

 

     March 31, 2010

Horsepower Range

   Revenue
Generating
Horsepower
   Percentage of
Revenue
Generating
Horsepower
    Number of
Units

0-499

   68,022    9   360

500-999

   70,912    9   115

1,000+

   620,770    82   410
               
   759,704    100   885
               
      December 31, 2009

Horsepower Range

   Revenue
Generating
Horsepower
   Percentage of
Revenue
Generating
Horsepower
    Number of
Units

0-499

   65,397    9   361

500-999

   74,826    10   121

1,000+

   613,105    81   405
               
   753,328    100   887
               

 

Page | 25


Net (Loss) Income Attributable to Regency Energy Partners LP. Net loss attributable to Regency Energy Partners LP was $612,000 in the three months ended March 31, 2010, compared to the net income of $148,389,000 in the three months ended March 31, 2009. The major components of this change were as follows:

 

   

$133,451,000 decrease due to the absence of gain associated with the contribution of RIGS to HPC;

 

   

$14,081,000 decrease in segment margin primarily due to the contribution of RIGS to HPC;

 

   

$8,118,000 increase in interest expense primarily due to the issuance of $250,000,000 of 9.375 percent senior notes due 2016 in May 2009 at a higher interest rate as compared to our credit facility interest rate;

 

   

$3,309,000 decrease in other income and deductions, net which primarily relate to the non-cash value change associated with the embedded derivative related to the Series A Preferred Units issued in September 2009. These decreases were partially offset by:

 

   

$7,577,000 increased income from an unconsolidated subsidiary (HPC) as there was a full quarter of operations in 2010 compared to only 14 days in 2009, plus the Haynesville Expansion Project and the Red River Lateral were in operation for two months in 2010; and

 

   

$3,631,000 decrease in operations and maintenance expenses primarily as a result of the absence of HPC’s operations and maintenance expenses in 2010, as well as a focus on cost saving measures.

Adjusted Total Segment Margin. Adjusted total segment margin decreased to $96,949,000 in the three months ended March 31, 2010 from $103,659,000 in the three months ended March 31, 2009. This was primarily attributable to a decrease of $11,554,000 in the transportation segment margin which was offset by the addition of $3,404,000 in adjusted gathering and processing segment margin and the addition of $5,913,000 in corporate and others segment.

Adjusted gathering and processing segment margin increased to $58,514,000 for the three months ended March 31, 2010 from $55,110,000 for the three months ended March 31, 2009, primarily due to the increased volumes in south Texas associated with the Eagle Ford Shale development.

We contributed RIGS to HPC on March 17, 2009. As a result, there was no transportation segment margin for the three months ended March 31, 2010.

Corporate and others segment margin increased to $6,737,000 in the three months ended March 31, 2010 from $824,000 in the three months ended March 31, 2009. The increase is primarily attributable to a $3,907,000 increase in management fees from HPC for general and administrative expenses.

Operation and Maintenance. Operation and maintenance expense decreased to $32,411,000 in the three months ended March 31, 2010 from $36,042,000 during the three months ended March 31, 2009. The decrease was primarily due to the following:

 

   

$2,286,000 decrease due to the absence of HPC’s operation and maintenance expenses in 2010; and

 

   

$1,345,000 decrease due to a focus on cost saving measures.

Gain on Sale of Asset, net. Gain on sale of asset, net decreased due to the absence in 2010 of the gain associated with the contribution of RIGS to HPC on March 17, 2009.

Depreciation and Amortization. Depreciation and amortization expense decreased to $27,475,000 in the three months ended March 31, 2010 from $27,889,000 in the three months ended March 31, 2009. The decrease was primarily due to the contribution of RIGS to HPC which was $2,448,000, offset by $2,034,000 increase related to various organic growth projects completed since March 31, 2009.

Interest Expense, Net. Interest expense, net increased to $22,345,000 in the three months ended March 31, 2010 from $14,227,000 in the three months ended in March 31, 2009. The increase is primarily attributable to:

 

   

$7,595,000 due to higher rates related to our senior notes interest rates as compared to our credit facility;

 

   

$1,780,000 write-off of loan fees upon the execution of the fifth amendment of our revolving credit facility; and

 

   

$475,000 less capitalized interest in the three months ended March 31, 2010 compared to the three months ended March 31, 2009; which was offset by;

 

   

$1,732,000 due to a lower amount of borrowings.

Other Income and Deductions, net. Other income and deductions, net decreased to an expense of $3,267,000 in the three months ended March 31, 2010 from an income of $42,000 during the three months ended March 31, 2009. This increase is primarily attributable to the non-cash value change in the embedded derivatives related to the Series A Preferred Units issued in September 2009.

HPC

Although we own a 43 percent interest in HPC, the following management discussion and analysis is for 100 percent of HPC’s consolidated results of operations. For comparative purposes only, we have combined the results of operations of RIG from January 1, 2009 to March 17, 2009, with the results of operations of HPC.

 

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Three Months Ended March 31, 2010 vs. March 31, 2009

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

 

     Three Months Ended March 31,             
     2010     2009    Change     Percent  
     (in thousands except percentages and volume data)        

Revenues

   $ 35,189      $ 14,155    $ 21,034      149 

Cost of sales

     1,310        599      711      119   
                         

Segment margin

     33,879        13,556      20,323      150   

Operation and maintenance

     4,774        2,611      2,163      83   

General and administrative

     4,318        248      4,070      1,641   

Depreciation and amortization

     6,321        3,117      3,204      103   
                         

Operating income

     18,466        7,580      10,886      144   

Interest expense

     (102     —        (102   N/M   

Other income and deductions, net

     39        104      (65   63   
                         

Net income

   $ 18,403      $ 7,684    $ 10,719      139 
                         

System inlet volumes (MMbtu/d)

     882,626        810,848      71,778      9

 

N/M - not meaningful

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

 

     Three Months Ended March 31,  
     2010     2009  
     (in thousands)  

Net income

   $ 18,403      $ 7,684   

Add (deduct):

    

Operation and maintenance

     4,774        2,611   

General and administrative

     4,318        248   

Depreciation and amortization

     6,321        3,117   

Interest expense

     102        —     

Other income and deductions, net

     (39     (104
                

Segment margin and adjusted segment margin

   $ 33,879      $ 13,556   
                

Net income increased to $18,403,000 in the three months ended March 31, 2010 from $7,684,000 in the three months ended March 31, 2009. The increase in net income was primarily attributable to the following:

 

   

$20,323,000 increase in segment margin since the Haynesville Expansion Project and the Red River Lateral were placed in service on January 27, 2010;

 

   

$4,070,000 increase in general and administrative expenses primarily due to the management fees paid to the Partnership;

 

   

$3,204,000 increase in depreciation and amortization expenses primarily due to the additional depreciation from the Haynesville Expansion Project and the Red River Lateral; and

 

   

$2,163,000 increase in operation and maintenance expenses primarily related to increased ad valorem taxes.

HPC’s adjusted EBITDA for the three months ended March 31, 2010 and 2009 are presented below.

 

     Three Months Ended March 31,
     2010    2009
     (in thousands)

Net income

   $ 18,403    $ 7,684

Add (deduct):

     

Depreciation and amortization

     6,321      3,117

Interest expense

     102      —  
             

EBITDA and adjusted EBITDA

   $ 24,826    $ 10,801
             

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

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

In addition to the information set forth in this report, further information regarding the Partnership’s critical accounting policies and estimates is included in Item 7 of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2009.

See Item 1, Note 1 - Organization and Summary of Significant Accounting Policies of this Form 10-Q for the description of recently issued accounting standards.

 

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OTHER MATTERS

Information regarding the Partnership’s commitments and contingencies is included in Note 6 Commitments and Contingencies to the condensed consolidated financial statements included in Item 1 of this report.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity

We expect our sources of liquidity to include:

 

   

cash generated from operations;

 

   

borrowing under our credit facility;

 

   

distributions received from unconsolidated subsidiaries;

 

   

asset sales;

 

   

debt offerings; and

 

   

issuance of additional partnership units.

We expect our growth capital expenditures to be approximately $180,000,000 in 2010, exclusive of our 43 percent proportionate share of the growth capital expenditures related to HPC. Our anticipated 2010 organic growth capital expenditures include $148,000,000 for the expansion of our gathering and processing facilities, $24,000,000 for additional compression for our contract compression segment, and $8,000,000 related to the corporate and others segment.

In addition, we expect to invest $23,000,000 in HPC in 2010.

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

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

Our working capital decreased to $10,447,000 at March 31, 2010 from $17,468,000 at December 31, 2009. This decrease was primarily due to the following factors:

 

   

an increase in other current liabilities of $12,131,000 due to the interest accrual on our senior notes, which pay interest semi-annually in June and December;

 

   

a decrease in cash and cash equivalents of $5,741,000;

 

   

a decrease in other current assets of $626,000; and was offset by

 

   

a net increase in trade account receivable, accrued revenues, related party receivables, trade accounts payable, accrued cost of gas and liquids, deferred revenue and related party payables of $6,817,000 due to the timing of our cash receipts and payments; and

 

   

a net increase in the market value of derivative assets and liabilities of $4,660,000 due to the decrease in commodity prices in the three months ended March 31, 2010.

Cash Flows from Operating Activities. Net cash flows provided by operating activities decreased to $32,781,000 in the three months ended March 31, 2010 from $36,331,000 in the three months ended March 31, 2009. The decrease is primarily due to the contribution of RIGS to HPC in March 2009.

Cash Flows from Investing Activities. Net cash flows used in investing activities increased to $48,043,000 in the three months ended March 31, 2010 from net cash flows provided by investing activities of $2,842,000 in the three months ended March 31, 2009. The increase is due to $20,210,000 increase in capital contribution associated with our investment in HPC, a $72,465,000 decrease in proceeds from asset sales and was offset by $41,790,000 decrease in capital expenditures.

Growth Capital Expenditures. Growth capital expenditures are capital expenditures made to acquire additional assets to increase our business, to expand and upgrade existing systems and facilities or to construct or acquire similar systems or facilities or to maintain existing system volumes and related cash flows. In the three months ended March 31, 2010, we incurred $28,624,000 of growth capital expenditures, exclusive of growth capital expenditure for HPC. Growth capital expenditures for the three months ended March 31, 2010 relates to $20,941,000 for organic growth projects in our gathering and processing segment and $7,683,000 for the fabrication of new compressor packages for our contract compression segment.

 

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Maintenance Capital Expenditures. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets or to maintain the existing operating capacity of our assets and extend their useful lives. In the three months ended March 31, 2010, we incurred $3,942,000 of maintenance capital expenditures.

Cash Flows from Financing Activities. Net cash flows provided by financing activities increased to $9,521,000 in the three months ended March 31, 2010 from net cash flows used in financing activities of $33,194,000 in the three months ended March 31, 2009. The increase is due to an increase of $62,005,000 borrowing under our revolving credit facility, offset by a $9,264,000 increase in debt and equity issuance costs and a $10,026,000 increase in distributions.

Credit Ratings. Our credit ratings as of March 31, 2010 are provided below.

 

     Moody’s    Standard & Poor’s

Regency Energy Partners LP

     

Outlook

   Stable    Stable

Senior notes due 2013

   B1    B

Senior notes due 2016

   B1    B

Corporate rating/total debt

   Ba3    BB-

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

 

   

The 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 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 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 March 31, 2010, the Partnership was in compliance with all of the financial covenants contained within the revolving credit agreement.

 

Item 3. Quantitative and Qualitative Disclosure about Market Risk

Commodity Price Risk. We are a net seller of NGL, condensate and natural gas as a result of our gathering and processing operations. The prices of these commodities are impacted by changes in supply and demand as well as market uncertainty. Our profitability and cash flow are affected by the inherent volatility of these commodities, which could adversely affect our ability to make distributions to our unitholders. We manage this commodity price exposure through an integrated strategy that includes management of our contract portfolio, matching sales prices of commodities with purchases, optimization of our portfolio by monitoring basis and other price differentials in operating areas, and the use of derivative contracts. In some cases, we may not be able to match pricing terms or to cover our risk to price exposure with financial hedges, and we may be exposed to commodity price risk. It is our policy not to take any speculative positions with derivative contracts.

On April 5, 2010, we entered into additional NGLs swaps to hedge a portion of our 2011 NGLs sales.

We have executed swap contracts settled against condensate, ethane, propane, butane, natural gas, and natural gasoline market prices. We continually monitor our hedging and contract portfolio and expect to continue to adjust our hedge positions as conditions warrant. We have hedged expected equity exposure to declines in prices for NGLs, condensate and natural gas volumes produced for our account in the approximate percentages set for below:

 

     As of March 31, 2010     As of April 5, 2010  
     2010     2011     2010     2011  

NGLs

   73   29   73   41

Condensate

   84   50   84   50

Natural gas

   74   23   74   23

 

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The following table sets forth certain information regarding our hedges for natural gas, NGLs, and WTI, outstanding at March 31, 2010. The relevant index price that we pay is the monthly average of the daily closing price for deliveries of commodities into Mont Belvieu, Texas, as reported by the Oil Price Information Service (OPIS). The relevant index price for natural gas is NYMEX on the pricing dates as defined by the swap contracts. The relevant index for WTI is the monthly average of the daily price of WTI as reported by the NYMEX.

 

Period

  

Underlying

   Notional Volume/Amount    We Pay    We Receive
Weighted Average Price
   Fair Value
Asset/(Liablity)
 
                         (in thousands)  

April 2010-September 2011

   Ethane    668 (MBbls)    Index    $0.53 ($/gallon)    $ (115

April 2010-September 2011

   Propane    435 (MBbls)    Index    1.26 ($/gallon)      2,768   

April 2010-December 2010

   Iso Butane    70 (MBbls)    Index    1.76 ($/gallon)      720   

April 2010-September 2011

   Normal Butane    223 (MBbls)    Index    1.56 ($/gallon)      1,037   

April 2010-September 2011

   Natural Gasoline    163 (MBbls)    Index    2.09 ($/gallon)      2,087   

April 2010-December 2011

   West Texas Intermediate Crude    320 (MBbls)    Index    104.22 ($/Bbl)      5,926   

April 2010-June 2011

   Natural gas    3,105,000 (MMBtu)    Index    6.16 ($/MMBtu)      4,992   

Credit risk adjustment

                 (89
                    
            Total Fair Value    $ 17,326   
                    

 

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Item 4. Controls and Procedures

Disclosure controls. At the end of the period covered by this report, an evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based on that evaluation, management, including the Chief Executive Officer and Chief Financial Officer of our managing general partner, concluded that our disclosure controls and procedures were effective as of March 31, 2010 to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is properly recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Internal control over financial reporting. There have been no changes in the Partnership’s internal controls over financial reporting that have materially affected, or are reasonably likely to affect, the Partnership’s internal controls over financial reporting.

PART II – OTHER INFORMATION

 

Item 1. Legal Proceedings

The information required for this item is provided in Note 6, Commitments and Contingencies, included in the notes to the unaudited condensed consolidated financial statements included under Part I, Item 1, which information is incorporated by reference into this item.

 

Item 1A. Risk Factors

You should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2009, which could materially affect our business, financial condition or future results. The risks discussed in our Annual Report on Form 10-K are not the only risks facing our Partnership.

Proposed TCEQ Rule. TCEQ has proposed a new Section 352 Oil and Gas Permit by Rule (PBR), which is applicable to gas pipeline facilities and provides an authorization for activities that produce more than a de minimis level of emissions, but too little emissions for other permitting options, if the conditions of PBR are met. If adopted, our compliance with the conditions in the proposed PBR may result in substantial increases in our capital expenditures and operating costs.

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

 

Item 6. Exhibits

The exhibits below are filed as a part of this report:

 

Exhibit 10.35 – Fifth Amended and Restated Credit Agreement, dated March 4, 2010 (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated March 4, 2010)
Exhibit 10.36 – Amendment Agreement to the Fifth Amended and Restated Credit Agreement, dated March 4, 2010 (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated March 4, 2010)
Exhibit 10.37 – Assignment and Assumption Agreement, dated April 30, 2010, by and between EFS Haynesville, LLC and Regency Haynesville Intrastate Gas LLC (Incorporated by reference to Exhibit 10.1 to our Form 8-K dated April 30, 2010)
Exhibit 10.38 – Voting Agreement, dated April 30, 2010, by and between EFS Haynesville, LLC and Regency Haynesville Intrastate Gas LLC (Incorporated by reference to Exhibit 10.2 to our Form 8-K dated April 30, 2010)
Exhibit 10.39 – First Amendment To Second Amended and Restated General Partnership Agreement of RIGS Haynesville Partnership Co. dated as of March 9, 2010

 

Exhibit 12.1 – Computation of Ratio of Earnings to Fixed Charges

 

Exhibit 31.1 – Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer

 

Exhibit 31.2 – Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer

 

Exhibit 32.1 – Section 1350 Certifications of Chief Executive Officer

 

Exhibit 32.2 – Section 1350 Certifications of Chief Financial Officer

 

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

    REGENCY ENERGY PARTNERS LP
    By: Regency GP LP, its general partner
    By: Regency GP LLC, its general partner
Date: May 7, 2010       /s/    LAWRENCE B. CONNORS        
      Lawrence B. Connors
     

Senior Vice President and Chief Accounting Officer

(Duly Authorized Officer)

 

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