EX-99.1 2 ex991.htm EARNINGS PRESS RELEASE DATED NOVEMBER 10, 2008 ex991.htm
Regency Energy Partners Reports Third-Quarter 2008 Results

Regency Explores Options Regarding Expansion of Louisiana Pipeline and
Announces Revised Growth Capital and Financing Objectives for 2009 and 2010


DALLAS, November 10, 2008 – Regency Energy Partners LP (Nasdaq: RGNC) announced today its adjusted EBITDA increased 69% to $67 million in the third quarter 2008, compared to $39 million in the third quarter 2007.  Revenue in the third quarter 2008 increased 85% to $547 million, compared to $296 million in the third quarter 2007.  Adjusted total segment margin increased 84% to $117 million in the third quarter 2008, compared to $64 million in the corresponding 2007 period.

Regency generated net income of $49 million in the three months ended September 30, 2008, compared to a loss of $10 million in the previous year’s period.  This $59 million increase is primarily related to expansion of the business, non-cash gains from risk management activities and the absence in 2008 of a debt-refinancing loss associated with the early termination penalty for Regency senior notes.

“Despite the impact of Hurricane Ike and a drastic reduction in commodity prices, Regency produced impressive year-over-year growth in our business. Our 2008 adjusted EBITDA guidance remains unchanged, although we anticipate coming in on the lower half of the range based on current commodity prices,” said Byron Kelley, chairman, president and chief executive officer of Regency.  “Also, with the current capital market conditions, Regency has reevaluated our future growth plans, and we are making appropriate capital expenditure reductions to continue to maximize unitholder value.”

REVIEW OF SEGMENT PERFORMANCE
 
Gathering & Processing - The Gathering & Processing segment includes Regency's natural gas processing and treating plants, low-pressure gathering pipelines and NGL pipeline activities. Adjusted segment margin for Gathering & Processing, which excludes non-cash hedging gains and losses related to the Gathering and Processing Segment, was $65 million for the quarter ended September 30, 2008, compared to $49 million for the third quarter 2007, a 34% increase.
 
Total throughput volumes for the Gathering & Processing segment averaged nearly 1.1 million MMbtu per day of natural gas, and processed NGLs averaged 21 thousand barrels per day for the quarter ended September 30, 2008, compared to 882 thousand MMbtu per day of natural gas and 23 thousand barrels for produced NGLs for the third quarter 2007.  Processed NGLs were lower primarily as a result of disruptions in third-party fractionation activities in Mont Belvieu, Texas, caused by Hurricane Ike.
 
Transportation - The Transportation segment includes Regency's natural gas transportation pipelines, and related facilities and activities.  Adjusted segment margin for the Transportation segment was $20 million for the third quarter 2008, 29% higher than the $15 million in the same quarter 2007. Total transportation throughput volumes for the Transportation segment averaged 795 thousand MMbtu per day of natural gas for the quarter ended September 30, 2008, compared to 789 thousand MMbtu per day of natural gas for the corresponding period in 2007.
 
Contract Compression - The Contract Compression segment provides customers with turnkey natural gas compression services to maximize natural gas and crude oil production, throughput and cash flow.  Regency's integrated solutions include a comprehensive assessment of a customer's natural gas contract compression needs, and the design and installation of a customized compression system.
 
Segment margin for Contract Compression segment was $33 million for the third quarter 2008. Regency’s revenue generating horsepower at the end of the third quarter 2008 was 742,804, compared to 669,804 of revenue generating horsepower at the end of the second quarter 2008, an 11% increase.
 
CASH DISTRIBUTIONS
 
On October 24, 2008, Regency announced a cash distribution of 44.5 cents per outstanding common and subordinated unit for the third quarter ended September 30, 2008. This distribution is equivalent to $1.78 on an annual basis and will be paid on November 14, 2008, to unitholders of record at the close of business on November 7, 2008.
 
In the third quarter 2008, Regency generated $48 million in cash available for distribution, representing coverage of 1.4 times the amount required to cover its announced distribution to common and subordinated unitholders, and 1.3 times the amount required to cover the distribution to all unitholders, including Class D units.  The Class D units will not participate in 2008 distributions and will convert to common units on a one-for-one basis on February 9, 2009.

Regency makes distribution determinations based on its cash available for distribution and the perceived sustainability of distribution levels over an extended period.  In addition to considering the cash available for distribution generated during the quarter, Regency takes into account cash reserves established with respect to prior distributions, seasonality of results, and its internal forecasts of adjusted EBITDA and cash available for distribution over an extended period.
 
2008 ORGANIC GROWTH PROJECTS

Regency’s $356 million of 2008 organic growth capital expenditures includes approximately $143 million to add compression to the Contract Compression segment,  approximately $97 million related to the expansion of RIGS, referred to as the Haynesville Expansion Project, and the remaining $116 million spent on the Gathering & Processing segment.

In the nine months ended September 30, 2008, Regency incurred $231 million of growth capital expenditures, primarily related to the purchase of additional compression systems for the Contract Compression segment; the construction of 20 miles of 10-inch pipeline and related plant modifications required to connect the Fashing Processing Plant to the Tilden Plant in South Texas; the construction of 40 miles of 10-inch diameter pipeline and compression facilities in West Texas; and the construction of pipeline, compression and treating facilities related to a joint venture in South Texas.  These projects were substantially completed in the three months ended September 30, 2008.
 
REVISED GROWTH CAPITAL AND FINANCING OBJECTIVES
 
“With the higher cost of capital our sector is now facing, we believe it is prudent to adapt by maintaining a solid balance sheet and preserving unitholder value,” said Kelley. “To reduce our dependence on the capital markets, Regency is revising our 2009 and 2010 growth plans to reduce our total debt and equity requirements by 50% to $850 million.”

“Specifically, Regency will reduce our 2009 and 2010 base business growth capital by $400 million, and redesign and downsize the Haynesville Expansion Project to further decrease capital requirements by $450 million,” Kelley continued.  “Over the long term, Regency intends to finance all of our capital with a debt to EBITDA ratio of approximately 4 times.  We intend to finance the Haynesville project initially through the issuance of debt followed by the issuance of equity when the equity markets improve.”

“Despite the lower capital investments, if we are able to implement the new plan under our current assumptions, we expect to be able to deliver strong growth over the next two years,” said Kelley.

HAYNESVILLE PROJECT UPDATE

In light of the recent volatility in the capital markets, Regency has elected to re-scope the Haynesville Expansion Project.  The availability of capital and the total cost of current financing options do not justify the project as originally envisioned.

“The newly scoped project will retain over 1 bcf/d of the original 1.45 bcf/d of increased capacity, and will cost approximately $650 million excluding capitalized interest and labor costs,” said Kelley.  “We have reduced the near-term capital requirements for the project without sacrificing our ability to expand the pipeline in the future.”

Regency is in ongoing discussions with producers, suppliers, contractors, banks and other financing providers related to the redesigned project.  In the near term, Regency will focus on obtaining firm transportation agreements for the rescoped project, and will seek to obtain acceptable financing for the project and satisfactory supplier arrangements.  If these conditions are met, Regency anticipates having the project in full-service by the end of 2009.

“Regency has made significant progress securing right-of-way permits and signing contracts with suppliers,” Kelley said. “While many producers are cutting back on drilling in other areas, we continue to see strong demand and promising economics for the Haynesville Shale and our project.”

Any delay of the Haynesville Expansion Project could result in Regency not being able to enter into contracts with the anchor shippers necessary for the company to finance and construct the project.  If Regency is not successful in these efforts, it may incur substantial costs for commitments made for materials and services.  As a result of these costs, Regency’s cash flow may decrease, possibly resulting in a reduction in distributions to unitholders.

Specifically, the success of Regency’s Haynesville Expansion Project is subject to the successful exploration and development of the Haynesville Shale, a new and emerging natural gas play. The results of producers’ exploratory drilling in new or emerging plays, such as the Haynesville Shale, are more uncertain than drilling results in areas that are developed and have established production.  Since the Haynesville Shale has limited production history, past drilling results in this area will be of limited help in predicting future drilling results in the area. Additionally, the commitment of Regency’s anchor shippers to utilize the expanded system is subject to the execution of definitive transportation agreements satisfactory to the parties.  To the extent that Regency does not enter into definitive transportation agreements on the terms contemplated by letters of intent or to the extent producers in the area are unable to execute their exploratory drilling and development plans in this area, the return on Regency’s investment from this project may not be as attractive as originally anticipated.

LIQUIDITY

Regency has experienced, and expects to continue to experience, substantial capital expenditure and working capital needs, particularly as a result of the Haynesville Expansion Project. Regency’s planned capital expenditures for 2008 and 2009 are expected to exceed substantially the net cash generated by operations. In addition to using borrowings under the revolving credit facility, Regency will need to raise additional financing from future debt or equity offerings to fund the budgeted capital expenditures for 2009.

Global financial markets and economic conditions have been, and continue to be, disruptive and volatile. The debt and equity capital markets have been distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions, have made, and will likely continue to make, it difficult to obtain funding. Also, the cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, refused to refinance existing debt at maturity or on terms similar to Regency’s current debt, and reduced and, in some cases, ceased to provide funding to borrowers.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss third-quarter 2008 results on Monday, November 10, 2008, at 10 a.m. Central Time (11 a.m. Eastern Time).
 
The dial-in number for the call is 1-800-599-9816 in the United States, or +1-617-847-8705 outside the United States, pass code 15068112.  A live webcast of the call can be accessed on the investor information page of Regency Energy Partners’ Web site at www.regencyenergy.com. The call will be available for replay for 7 days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) pass code 14387729.
 
NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-generally accepted accounting principles ("non-GAAP") financial measures of adjusted EBITDA, EBITDA, cash available for distribution, adjusted segment margin, segment margin, adjusted total segment margin, and total segment margin,  which are key measures of the Partnership’s financial performance.  The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated and presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our non-GAAP financial measures should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as a measure of operating performance, liquidity or ability to service debt obligations.

We define Adjusted EBITDA as net income (loss) plus interest expense, net, depreciation and amortization expense, income tax expense, non-cash loss (gain) from risk management activities and losses from non-cash commodity put option expirations. In deriving adjusted EBITDA for the third quarter of 2008, we made positive adjustments for losses on the sale of assets and non-capitalizable acquisition expenses because these are non-recurring items.

Adjusted EBITDA is used as a supplemental performance measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, to assess:

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

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

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

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

Our Adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate Adjusted EBITDA in the same manner.

We define cash available for distribution as:

·  
Adjusted EBITDA
·  
plus non-cash items affecting adjusted EBITDA, such as non-cash unit-based compensation expense related to our Long-Term Incentive Plan (LTIP),
·  
minus interest expense,
·  
minus maintenance capital expenditures,
·  
minus  (plus) income tax expense (benefit), and
·  
plus cash proceeds from asset sales, if any.

Cash available for distribution is used as a supplemental liquidity measure by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to approximate the amount of operating surplus generated by the Partnership during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Cash available for distribution is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

We define adjusted segment margin as segment operating revenues (including transportation and other service fees) less segment cost of sales plus non cash gains (losses) from risk management activities and non-cash losses from commodity put option expirations. Adjusted segment margin is included as a supplemental disclosure because it is a primary performance measure used by management as it represents the results of product purchases and sales, a key component of our operations.

We define adjusted total segment margin as total operating revenues less the cost of sales plus non cash gain (losses) from risk management activities and losses from non-cash commodity put option expirations.  Our adjusted total segment margin equals the sum of our Gathering and Processing adjusted segment margin, Transportation segment margin, and our Contract Compression segment margin.

Our segment margin measures may not be comparable to similarly titled measures of other companies because other entities may not calculate segment margin amounts in the same manner.

Schedules presenting Regency's consolidated statements of operations, segment margin and operating information by segment, as well as schedules reconciling adjusted EBITDA, cash available for distribution, adjusted segment margin, and adjusted total segment margin to the most directly comparable financial measures calculated and presented in accordance with GAAP are available on Regency's Web site at www.regencyenergy.com and as an attachment to this document.

This press release may contain forward-looking statements regarding Regency Energy Partners, including projections, estimates, forecasts, plans and objectives. These statements are based on management's current projections, estimates, forecasts, plans and objectives and are not guarantees of future performance. In addition, these statements are subject to certain risks, uncertainties and other assumptions that are difficult to predict and may be beyond our control. These risks and uncertainties include changes in laws and regulations impacting the gathering and processing and contract compression businesses, the level of creditworthiness of the Partnership's counterparties, the Partnership's ability to access the debt and equity markets, the Partnership's 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 the Partnership's transactions, changes in commodity prices, interest rates, demand for the Partnership's services, weather and other natural phenomena, industry changes including the impact of consolidations and changes in competition, the Partnership's ability to obtain required approvals for construction or modernization of the Partnership's facilities and the timing of production from such facilities, and the effect of accounting pronouncements issued periodically by accounting standard setting boards. Therefore, actual results and outcomes may differ materially from those expressed in such forward-looking information.

In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements might not occur or might occur to a different extent or at a different time than the Partnership has described. The Partnership undertakes no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Regency Energy Partners LP (Nasdaq: RGNC) is a growth-oriented, midstream energy partnership engaged in the gathering, contract compression, processing, marketing and transporting of natural gas and natural gas liquids.  Regency’s general partner is majority-owned by an affiliate of GE Energy Financial Services, a unit of GE (NYSE: GE).  For more information, visit the Regency Energy Partners LP Web site at www.regencyenergy.com.
 
 
CONTACT:
 
 
Investor Relations:
 
Shannon Ming
Vice President, Investor Relations & Communications
Regency Energy Partners
214-840-5467
shannon.ming@regencygas.com

Media Relations:
Emily Bruce
HCK2 Partners
972-716-0500 x21
emily.bruce@hck2.com


 

 
Regency Energy Partners LP
  
Condensed Consolidated Statements of Operations
  
Unaudited
  
(in thousands)
  
                         
                         
   
Three Months Ended Sep. 30,
    
Year to Date Sep. 30,
  
 
  
2008
    
2007
    
2008
    
2007
  
                         
                         
REVENUE
                        
Gas sales
   $ 323,411     $ 175,107     $ 922,872     $ 538,360  
NGL sales
     120,538       90,605       355,558       237,382  
Gathering, transportation and other fees (includes related party revenues
                        
    of $939, $541, $2,865 and $1,325 )
     74,267       30,478       206,429       69,553  
Unrealized/realized gain/(loss) from risk management activities
     6,817       (8,088 )     (39,600 )     (10,798 )
Other
     22,142       7,722       53,856       20,584  
    Total revenue
     547,175       295,824       1,499,115       855,081  
                                 
OPERATING COSTS AND EXPENSES
                                
Cost of gas and liquids (includes related party amounts of $632, $656,
                        
    $1,878 and $13,829)
     408,165       234,946       1,168,441       696,644  
Operation and maintenance
     33,688       18,134       95,049       41,031  
General and administrative
     13,976       6,983       38,784       32,928  
Loss (gain) on sale of assets
     (34 )     (777 )     434       1,562  
Management services termination fee
     -       -       3,888       -  
Transaction expense
     2       -       536       -  
Depreciation and amortization
     26,422       14,993       74,638       39,123  
     Total operating costs and expenses
     482,219       274,279       1,381,770       811,288  
                                 
OPERATING INCOME
     64,956       21,545       117,345       43,793  
                                 
OTHER INCOME AND DEDUCTIONS
                                
Interest expense, net
     (16,072 )     (10,894 )     (48,261 )     (41,740 )
Loss on debt refinancing
     -       (21,200 )     -       (21,200 )
Minority interest
     (162 )     (156 )     (165 )     (130 )
Other income and deductions, net
     118       713       450       951  
     Total other income and deductions
     (16,116 )     (31,537 )     (47,976 )     (62,119 )
                                 
INCOME (LOSS) BEFORE INCOME TAXES
     48,840       (9,992 )     69,369       (18,326 )
                                 
Income tax expense (benefit)
     (67 )     (160 )     142       65  
                                 
NET INCOME (LOSS)
   $ 48,907     $ (9,832 )   $ 69,227     $ (18,391 )

 
 
 
 
Segment Financial and Operating Data


   
Three Months Ended Sep. 30,
  
Year to Date Sep. 30,
  
($ in thousands)
  
2008
    
2007
    
2008
    
2007
  
                         
Gathering and Processing Segment
                        
Financial data:
                        
Segment margin (1)
   $ 86,642     $ 45,590     $ 187,138     $ 115,467  
Adjusted segment margin
   $ 65,051     $ 48,580     $ 186,120     $ 118,766  
Operating data:
                                
Throughput (MMbtu/d)
     1,082,139       882,008       998,518       794,173  
NGL gross production (BBls/d)
     21,386       22,655       22,323       21,233  
                                 
(1) Segment margin and throughput volumes in 2007 vary from previously disclosed amounts due to pooling accounting for our FrontStreet
  
assets, effective June 18, 2007, acquired on January 7, 2008.
                  
                                 
                                 
                                 
   
Three Months Ended Sep. 30,
  
Year to Date Sep. 30,
  
($ in thousands)
  
2008
    
2007
    
2008
    
2007
  
                                 
Transportation Segment
                                
Financial data:
                                
Segment margin
   $ 19,718     $ 15,288     $ 58,215     $ 42,970  
Adjusted segment margin
   $ 19,718     $ 15,250     $ 58,215     $ 42,275  
Operating data:
                                
Throughput (MMbtu/d)
     795,104       788,789       773,562       757,367  
                                 
                                 
                                 
                                 
   
Three Months Ended Sep 30,
  
Year to Date Sep. 30,
  
($ in thousands)
  
2008
    
2007
    
2008
    
2007
  
                                 
Contract Compression Segment (2)
                                
Financial data:
                                
Segment margin
   $ 32,650     $ -     $ 85,321     $ -  
                                 
(2) Contract Compression segment was acquired in January 2008.
                
                                 
   
At June 30,
    
At September 30,
  
Contract Compression Segment (2)
  
2008
    
2007
    
2008
    
2007
  
Operating data:
                                
Revenue generating horsepower
     669,804       -       742,804       -  
Average horsepower per revenue generating compression unit
     849       -       851       -  
                                 
(2) Contract Compression segment was acquired in January 2008.
                

 
 
 

Reconciliation of Non-GAAP Measures to GAAP Measures


   
Three Months Ended Sep. 30,
    
Year to Date Sep. 30,
  
($ in thousands)
  
2008
    
2007
    
2008
    
2007
  
                         
Net income (loss)
   $ 48,907     $ (9,832 )   $ 69,227     $ (18,391 )
Income tax expense (benefit)
     (67 )     (160 )     142       65  
Interest expense, net
     16,072       10,894       48,261       41,740  
Depreciation and amortization
     26,422       14,993       74,638       39,123  
EBITDA (a)
   $ 91,334     $ 15,895     $ 192,268     $ 62,537  
Non-cash loss (gain) from risk management activities
     (21,591 )     2,160       (1,018 )     377  
Non-cash put option expiration
     -       792       -       2,227  
LTIP accelerated vesting charge
     -       -       -       11,928  
Loss (gain) on sale of assets
     (34 )     (777 )     434       1,562  
Loss on debt refinancing
     -       21,200       -       21,200  
Management services termination fee
     -       -       3,888       -  
Acquisition expenses
     2       -       492       -  
Other income/expense
     (3,134 )     -       (2,229 )     6  
Management fee
     -       69       -       69  
Adjusted EBITDA
   $ 66,577     $ 39,339     $ 193,835     $ 99,906  

 
 
 

Reconciliation of “cash available for distribution” to net cash flows provided by operating activities and to net income


   
Three Months Ended
  
($ in thousands)
  
Sep. 30, 2008
  
       
  Net cash flows provided by operating activities
   $ 62,346  
      Add (deduct):
        
              Depreciation and amortization
     (27,153 )
              Minority interest in income
     (165 )
              Risk management portfolio value changes
     21,591  
              Unit based compensation expenses
     (1,248 )
              Gain from insurance settlement
     3,282  
              Accrued revenues and accounts receivable
     (61,700 )
              Loss on sale of assets
     34  
              Other current assets
     (2,952 )
              Accounts payable and accrued liabilities
     64,213  
              Other current liabilities
     (7,134 )
              Other assets
     (2,207 )
  Net Income
   $ 48,907  
      Add (deduct):
        
              Income tax benefit
     (67 )
              Interest expense, net
     16,072  
              Depreciation and amortization
     26,422  
  EBITDA
   $ 91,334  
      Add (deduct):
        
              Non-cash gain from risk management activities
     (21,591 )
              Gain on sale of assets
     (34 )
              Proceeds from insurance settlement
     (3,134 )
              Transaction expense (a)
     2  
  Adjusted EBITDA
   $ 66,577  
      Add (deduct):
        
              Unit based compensation expenses
     1,248  
              Interest expense, excluding capitalized interest
     (15,798 )
              Maintenance capital expenditures
     (3,948 )
              Proceeds from sale of assets
     116  
              Income tax benefit
     67  
  Cash available for distribution
   $ 48,262  
         
(a) Acquisition-related costs for the FrontStreet acquisition were expensed under a method similar to pooling accounting and would have been capitalized under the purchase method of accounting.
  
 
  

 
 
 

Non-GAAP Adjusted Segment Margin to GAAP Net Income (Loss)


   
Three Months Ended Sep. 30,
    
Year to Date Sep. 30,
  
($ in thousands)
  
2008
    
2007
    
2008
    
2007
  
                         
Net income (loss)
   $ 48,907     $ (9,832 )   $ 69,227     $ (18,391 )
Add:
                                
Operation and maintenance
     33,688       18,134       95,049       41,031  
General and administrative
     13,976       6,983       38,784       32,928  
Management services termination fee
     -       -       3,888       -  
Transaction expense
     2       -       536       -  
Loss (gain) on sale of assets
     (34 )     (777 )     434       1,562  
Depreciation and amortization
     26,422       14,993       74,638       39,123  
Interest expense, net
     16,072       10,894       48,261       41,740  
Loss on debt refinancing
     -       21,200       -       21,200  
Other income and deductions, net
     (118 )     (713 )     (450 )     (951 )
Minority interest
     162       156       165       130  
Income tax expense (benefit)
     (67 )     (160 )     142       65  
Total Segment Margin
     139,010       60,878       330,674       158,437  
Non-cash loss (gain) from risk management activities
     (21,591 )     2,160       (1,018 )     377  
Non-cash put option expiration
     -       792       -       2,227  
Adjusted Total Segment Margin
     117,419       63,830       329,656       161,041  
Transportation segment margin
     19,718       15,288       58,215       42,970  
Non-cash gain from risk management activities
     -       (38 )     -       (695 )
Adjusted Segment Margin for Transportation
     19,718       15,250       58,215       42,275  
Contract Compression Segment Margin
     32,650       -       85,321       -  
Adjusted Segment Margin for Gathering and Processing
   $ 65,051     $ 48,580     $ 186,120     $ 118,766