Regency Energy Partners Reports Increased First Quarter 2014 Adjusted EBITDA

DALLAS--()--Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the first-quarter ended March 31, 2014.

The results presented herein have been retrospectively adjusted to combine Regency’s results with the results of Southern Union Gathering Company (“SUGS”) for the three months ended March 31, 2013, due to the as-if pooling accounting treatment required for an acquisition between commonly controlled entities.

For first quarter 2014, adjusted EBITDA increased 71 percent to $205 million, compared to $120 million in 2013, primarily due to volume growth in the gathering and processing segment, which includes the addition of 11 days of PVR operations, volume growth at the Lone Star Joint Venture, as well as an increase in revenue generating horsepower in the contract services segment.

For first quarter 2014, Regency generated $182 million in distributable cash flow (“DCF”), compared to $101 million for first quarter 2013. DCF for the first quarter of 2014 has been adjusted to include a full quarter DCF contribution related to the PVR acquisition.

Net income attributable to Regency increased to $9 million for first quarter 2014, compared to a net loss of $29 million for first quarter 2013. This increase was primarily due to an increase in total segment margin and an increase in income from unconsolidated affiliates; partially offset by increased depreciation, depletion and amortization, increased interest expense, and increased operation and maintenance expense.

“Regency’s legacy assets experienced strong performance in the first quarter, where we saw significant volume growth in our gathering and processing and NGL services businesses, as well as a strong increase in revenue generating horsepower for our contract compression business,” said Mike Bradley, president and chief executive officer of Regency. “This growth was driven by the ramp up of our growth projects completed last year, along with increased drilling activity in the majority of our operating regions.”

“Also during the quarter, we completed our merger with PVR Partners, which contributed incremental earnings for the period since closing. We continue to expect our legacy assets, as well as the PVR assets, to provide significant expansion opportunities in 2014 and 2015 to keep pace with increasing volumes and producer demand,” continued Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 44 percent to $225 million for first quarter 2014, compared to $156 million for first quarter 2013.

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, selling or delivering pipeline-quality natural gas and NGLs to various markets and pipeline systems, gathering of oil (crude and/or condensate, a lighter oil) received from producers, and the gathering and disposing of salt water. This segment also includes ELG, which operates natural gas gathering, oil pipeline, and oil stabilization facilities in south Texas, the Partnership’s 33.33% membership interest in Ranch JV, which processes natural gas delivered from NGL - rich shale formations in west Texas, and the Partnership’s 51% interest in Aqua - PVR, which transports and supplies fresh water to natural gas producers in the Marcellus shale in Pennsylvania. The Partnership completed the SUGS acquisition on April 30, 2013, which was a reorganization of entities under common control. Therefore, the Gathering and Processing segment amounts have been retrospectively adjusted to reflect the SUGS acquisition for the three months ended March 31, 2013.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $166 million for first quarter 2014, compared to $107 million for first quarter 2013. The increase was primarily due to volume growth in south and west Texas, and north Louisiana, including a $15 million contribution from the PVR and Hoover acquisitions.

Total throughput volumes for the Gathering and Processing segment increased to 2.7 million MMbtu per day of natural gas for first quarter 2014, including 359 thousand MMBtu per day related to the PVR and Hoover acquisitions, compared to 2.0 million MMbtu per day of natural gas for first quarter 2013. Processed NGLs increased to 101,000 barrels per day for first quarter 2014, compared to 82,700 barrels per day for first quarter 2013.

Contract Services – We own and operate a fleet of compressors used to provide turn-key natural gas compression services for customer specific systems. We also own and operate a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling and dehydration.

Segment margin for the Contract Services segment, including both revenues from external customers as well as intersegment revenues, was $56 million for first quarter 2014, compared to $47 million for first quarter 2013. The increase in segment margin is primarily due to the increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of March 31, 2014, the Contract Compression segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,120,000, compared to 891,000 as of March 31, 2013, inclusive of 47,000 and 38,000, respectively, of revenue generating horsepower utilized by the Gathering and Processing segment.

Natural Resources - The Partnership is involved in the management of coal and natural resources properties and the related collection of royalties. The Partnership also earns revenues from other land management activities, including selling standing timber, leasing coal-related infrastructure facilities, and collecting oil and gas royalties. This segment also includes the Partnership’s 50% interest in Coal Handling, which owns and operates end-user coal handling facilities.

Natural Resources segment margin was $2 million for March 21, 2014 (the date of acquisition) to March 31, 2014. Coal royalty tonnage for the same period was 472,000, for an average royalty per ton of $3.89.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $5 million for first quarter 2014 and for first quarter 2013.

Natural Gas Transportation – We own a 49.99% general partner interest in RIGS Haynesville Partnership Co. (“HPC”), which owns the Regency Intrastate Gas System (“RIGS”), a 450-mile intrastate pipeline that delivers natural gas from northwest Louisiana to downstream pipelines and markets, and a 50% membership interest in the Midcontinent Express Pipeline (“MEP”), which owns a 500-mile interstate natural gas pipeline stretching from southeast Oklahoma through northeast Texas, northern Louisiana and central Mississippi to an interconnect with the Transcontinental Gas Pipe Line system in Butler, Alabama. This segment also includes Gulf States, which owns a 10-mile interstate pipeline that extends from Harrison County, Texas to Caddo Parish, Louisiana.

HPC consists solely of the Regency Intrastate Gas System and is operated by Regency. Income from unconsolidated affiliates for HPC was $6 million for first quarter 2014, compared to $9 million for first quarter 2013. This decrease was primarily due to the expiration of certain contracts that were not renewed, as well as a customer declaring bankruptcy on April 1, 2013. Total throughput volumes for HPC averaged 613,000 MMbtu per day of natural gas for first quarter 2014, compared to 714,000 MMbtu per day for first quarter 2013.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline and is operated by Kinder Morgan Energy Partners L.P. Income from unconsolidated affiliates for the MEP Joint Venture was $11 million for first quarter 2014 and $10 million for first quarter 2013. Total throughput volumes for the MEP Joint Venture averaged 1.3 million MMbtu per day of natural gas for first quarter 2014 and 1.5 million MMbtu per day for first quarter 2013.

NGL Services – We own a 30% membership interest in the Lone Star Joint Venture, which owns a diverse set of midstream energy assets including pipelines, transportation, storage, fractionation and processing facilities located in Texas, Mississippi and Louisiana. The Lone Star Joint Venture owns and operates NGL storage, fractionation and transportation assets and is operated by Energy Transfer Partners, L.P.

Income from unconsolidated affiliates for NGL Services was $25 million for first quarter 2014 and $16 million for first quarter 2013. Transportation volumes averaged 184,000 barrels per day for first quarter 2014, compared to 153,000 barrels per day for first quarter 2013. Refinery Services throughput averaged 11,000 barrels per day for first quarter 2014, compared to 17,000 barrels per day for first quarter 2013. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 135,000 barrels per day for first quarter 2014, compared to 51,000 barrels per day for first quarter 2013.

ORGANIC GROWTH

For the quarter-ended March 31, 2014, Regency incurred $188 million of growth capital expenditures; $83 million for the Gathering and Processing segment, $80 million for the Contract Services segment, $23 million for the NGL Services segment and $2 million for the Transportation segment.

For the quarter-ended March 31, 2014, Regency incurred $22 million of maintenance capital expenditures.

In 2014, Regency expects to invest approximately $1.22 billion in growth capital expenditures, of which $860 million is related to the Gathering and Processing segment, inclusive of expenditures related to the recently acquired Hoover midstream business and PVR business, $250 million is related to the Contract Services segment and $110 million is related to the NGL Services segment.

In addition, Regency expects to invest approximately $90 million in maintenance capital expenditures in 2014, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On April 28, 2014, Regency announced a cash distribution of $0.48 per outstanding common unit for the first-quarter ended March 31, 2014. This distribution is equivalent to $1.92 per outstanding common unit on an annual basis and will be paid on May 15, 2014, to unitholders of record at the close of business on May 8, 2014.

Based on the terms of the partnership agreement, the Series A Preferred Units were paid a quarterly distribution of $0.445 per unit for the first quarter-ended March 31, 2014, on the same schedule as set forth above.

For the first quarter 2014, Regency generated $182 million in distributable cash flow, representing 1.02 times the amount required to cover its announced distribution to unitholders.

Regency makes distribution determinations based on its distributable cash flow 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, timing of organic growth projects and its internal forecasts of adjusted EBITDA and distributable cash flow over an extended period. Distributions are determined by the Board of Directors and are driven by the long-term sustainability of the business.

TELECONFERENCE

Regency Energy Partners will hold a quarterly conference call to discuss its first-quarter 2014 results Wednesday, May 7, 2014, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-877-703-6107 in the United States, or +1-857-244-7306 outside the United States, passcode 91132423. A live webcast of the call may be accessed on the Investor Relations page of Regency’s website at www.regencyenergy.com. The call will be available for replay for seven days by dialing 1-888-286-8010 (from outside the U.S., +1-617-801-6888) passcode 12695444. A replay of the broadcast will also be available on the Partnership’s website for 30 days.

NON-GAAP FINANCIAL INFORMATION

This press release and the accompanying financial schedules include the non-GAAP financial measures of:

  • EBITDA;
  • adjusted EBITDA;
  • cash available for distribution;
  • segment margin;
  • total segment margin;
  • adjusted segment margin; and
  • adjusted total segment margin.

These financial metrics 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. Reconciliations of these non-GAAP financial measures to our GAAP financial statements are included in the Appendix.

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

  • non-cash loss (gain) from commodity and embedded derivatives;
  • non-cash unit-based compensation;
  • loss (gain) on asset sales, net;
  • loss on debt refinancing;
  • other non-cash (income) expense, net;
  • our interest in ELG adjusted EBITDA less EBITDA attributable to ELG; and
  • our interest in adjusted EBITDA from unconsolidated affiliates less income from unconsolidated affiliates.

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.

Adjusted EBITDA is the starting point in determining cash available for distribution, which is an important non-GAAP financial measure for a publicly traded partnership.

We define distributable cash flow as adjusted EBITDA:

  • minus interest expense, excluding capitalized interest;
  • minus maintenance capital expenditures;
  • minus distributions to Series A Preferred Units;
  • plus cash proceeds from asset sales, if any; and
  • other adjustments.

Distributable cash flow 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 us during a specific period and to assess our ability to make cash distributions to our unitholders and our general partner. Distributable cash flow is not the same measure as operating surplus or available cash, both of which are defined in our partnership agreement.

Neither EBITDA nor adjusted EBITDA should 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. EBITDA and adjusted EBITDA may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA or adjusted EBITDA in the same manner. EBITDA and adjusted EBITDA do not include interest expense, income tax expense or depreciation and amortization expense. Because we have borrowed money to finance our operations, interest expense is a necessary element of our costs and our ability to generate cash available for distribution. Because we use capital assets, depreciation and amortization are also necessary elements of our costs. Therefore, any measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net earnings determined under GAAP, as well as EBITDA and adjusted EBITDA, to evaluate our performance.

We define segment margin, generally, as revenues minus cost of sales. We calculate our Gathering and Processing segment margin and Natural Gas Transportation segment margin as revenues generated from operations less the cost of natural gas and NGLs purchased and other costs of sales, including third-party transportation and processing fees. We do not record segment margin for our investments in unconsolidated affiliates (HPC, MEP, Lone Star, Ranch JV, Aqua – PVR and Coal Handling) because we record our ownership percentages of their net income as income from unconsolidated affiliates in accordance with the equity method of accounting. We calculate our Contract Services segment margin as revenues minus direct costs, primarily compressor unit repairs, associated with those revenues. Segment margin for the Natural Resources segment margin is generally equal to total revenues as there is typically minimal cost of sales associated with the management and leasing of properties. We calculate total segment margin as the sum of segment margin of our segments less intersegment eliminations. We define adjusted segment margin as segment margin adjusted for non-cash (gains) losses from commodity derivatives, the 40% of ELG margin attributable to the holder of the noncontrolling interest and our 33.33% portion of Ranch JV margin. Our adjusted total segment margin equals the sum of our operating segments’ adjusted segment margins or segment margins, as applicable, including intersegment eliminations.

Total segment margin and adjusted total segment margin are included as a supplemental disclosure because they are primary performance measures used by our management as they represent the result of product sales, service fee revenues and product purchases, a key component of our operations. We believe total segment margin and adjusted total segment margin are important measures because they are directly related to our volumes and commodity price changes.

Operation and maintenance expense is a separate measure used by management to evaluate operating performance of field operations. Direct labor, insurance, property taxes, repair and maintenance, utilities and contract services comprise the most significant portion of our operation and maintenance expenses. These expenses are largely independent of the volumes we transport or process and fluctuate depending on the activities performed during a specific period. We do not deduct operation and maintenance expenses from total revenue in calculating total segment margin and adjusted total segment margin because we separately evaluate commodity volume and price changes in these margin amounts.

As an indicator of our operating performance, total segment margin or adjusted total segment margin should not be considered an alternative to, or more meaningful than, net income as determined in accordance with GAAP. Our total segment margin and adjusted total segment margin may not be comparable to a similarly titled measure of another company because other entities may not calculate these measures in the same manner.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

These and other risks and uncertainties are discussed in more detail in filings made by the Partnership with the Securities and Exchange Commission, which are available to the public. 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 is a growth-oriented master limited partnership engaged in natural gas gathering and processing, transportation, contract compression and treating, crude oil gathering, water gathering and disposal, natural resource management, and natural gas liquids transportation, fractionation and storage. Regency’s general partner is owned by Energy Transfer Equity, L.P. (NYSE: ETE).

   

Condensed Consolidated Balance Sheets

 
Regency Energy Partners LP
Condensed Consolidated Balance Sheets
($ in millions)
 
March 31, 2014 December 31, 2013
Assets
Current assets $ 560 $ 400
Property, plant and equipment, net 7,321 4,418
Investment in unconsolidated affiliates 2,178 2,097
Other assets, net 84 57
Intangible assets, net 3,568 682
Goodwill   1,486   1,128
Total Assets $ 15,197 $ 8,782
 
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities $ 669 $ 475
Other long-term liabilities 69 49
Long-term debt   5,564   3,310
Total Liabilities $ 6,302 $ 3,834
 
Series A Preferred Units 32 32
 
Partners' capital 8,766 4,814
Noncontrolling interest   97   102
Total Partners' Capital and Noncontrolling Interest   8,863   4,916
Total Liabilities and Partners' Capital and Noncontrolling Interest $ 15,197 $ 8,782
 
   

Condensed Consolidated Statements of Operations

 
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
 
Three Months Ended March 31,
  2014     2013  
 
REVENUES $ 863 $ 540
 
OPERATING COSTS AND EXPENSES
Cost of sales 638 387
Operation and maintenance 78 69
General and administrative 33 33
(Gain) loss on asset sales, net (2 ) 1
Depreciation, depletion and amortization   94     65  
Total operating costs and expenses 841 555
 
OPERATING INCOME (LOSS) 22 (15 )
 
Income from unconsolidated affiliates 43 35
Interest expense, net (56 ) (37 )
Other income and deductions, net   2     (14 )
INCOME (LOSS) BEFORE INCOME TAXES 11 (31 )
Income tax benefit   (1 )   (2 )
NET INCOME (LOSS) $ 12 $ (29 )
Net income attributable to noncontrolling interest   (3 )   -  
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ 9   $ (29 )
 
Amount allocated to common units $ 1 $ (9 )
Weighted average number of common units outstanding 226,046,232 170,952,804
Basic income (loss) per common unit $ 0.00 $ (0.06 )
Diluted income (loss) per common unit $ 0.00 $ (0.06 )
 
   

Segment Financial and Operating Data

 
Three Months Ended March 31,
  2014   2013
($ in millions)
Gathering and Processing Segment
Financial data:
Segment margin $ 166 $ 104
Adjusted segment margin 166 107
Operating data:
Throughput (MMbtu/d) 2,662,000 1,990,000
NGL gross production (Bbls/d) 101,000 82,700
 
Three Months Ended March 31,
  2014   2013
($ in millions)
Contract Services
Financial data:
Segment margin $ 56 $ 47
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower 1,120,000 891,000
 

Period from March 21, 2014
(the date of acquisition) to
March 31, 2014

Three Months Ended March 31,

    2013
($ in millions)
Natural Resources
Financial data:
Segment margin * $ 2 $ -
Operating data:
Coal royalty tonnage 472,000 -
Average coal royalties per ton $ 3.89 $ -
 
* The Natural Resources segment was acquired in the PVR acquisition on March 21, 2014.
 
Three Months Ended March 31,
  2014   2013
($ in millions)
 
Corporate Segment
Financial data:
Segment margin $ 5 $ 5
 
 

Reconciliation of Non-GAAP Measures to GAAP Measures

       
Three Months Ended March 31,
  2014     2013  
($ in millions)
Net income (loss) $ 12 $ (29 )
Add (deduct):
Interest expense, net 56 37
Depreciation, depletion and amortization 94 65
Income tax benefit   (1 )   (2 )
EBITDA (1) $ 161 $ 71
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2) 75 63
Income from unconsolidated affiliates (43 ) (35 )
Non-cash loss from commodity and embedded derivatives 4 18
Other income, net   8     3  
Adjusted EBITDA $ 205   $ 120  
 
(1) Earnings before interest, taxes, depreciation and amortization.
 
(2) The following table presents reconciliations of net income to adjusted EBITDA for our unconsolidated affiliates, on a 100% basis, and our interest in adjusted EBITDA for the three months ended March 31, 2014 and 2013:
 
Three months ended March 31, 2014
HPC   MEP   Lone Star Ranch JV Total
Net Income (Loss) $ 15 $ 21 $ 83 $ 6
Add:
Depreciation and amortization 10 17 25 1
Interest expense, net 3 13 - -
Other expenses, net   -     -     1     -  
Adjusted EBITDA   28     51     109     7  
Ownership interest   49.99 %   50 %   30 %   33.33 %  
Partnership's interest in Adjusted EBITDA $ 14   $ 26   $ 33   $ 2   $ 75
 
Operating data
Throughput (MMbtu/d) 613,000 1,268,000 N/A 120,000
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 184,000 N/A
Refinery - Throughput (Bbls/d) N/A N/A 11,000 N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A 135,000 N/A
 
Three months ended March 31, 2013
HPC   MEP   Lone Star Ranch JV Total
Net Income (Loss) $ 20 $ 21 $ 55 $ -
Add:
Depreciation and amortization 9 17 20 1
Interest expense, net   -     13     1     -  
Adjusted EBITDA   29     51     76     1  
Ownership interest   49.99 %   50 %   30 %   33.33 %  
Partnership's interest in Adjusted EBITDA $ 14   $ 26   $ 23   $ -   $ 63
 
Operating data
Throughput (MMbtu/d) 714,000 1,463,000 N/A 53,000
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 153,000 N/A
Refinery - Throughput (Bbls/d) N/A N/A 17,000 N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A 51,000 N/A
 
 

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

 

 

Three Months Ended March 31,
  2014     2013  
($ in millions)
Net Income (Loss) $ 12 $ (29 )
Add (Deduct):
Operation and maintenance 78 69
General and administrative 33 33
(Gain) loss on asset sales, net (2 ) 1
Depreciation, depletion and amortization 94 65
Income from unconsolidated affiliates (43 ) (35 )
Interest expense, net 56 37
Other income and deductions, net (2 ) 14
Income tax benefit   (1 )   (2 )
Total Segment Margin 225 153
Non-cash loss from commodity derivatives 3 4
Segment margin related to the noncontrolling interest (6 ) (2 )
Segment margin related to ownership percentage in Ranch JV   3     1  
Adjusted Total Segment Margin $ 225   $ 156  
 
Gathering & Processing Segment Margin $ 166 $ 104
Non-cash loss from commodity derivatives 3 4
Segment margin related to the noncontrolling interest (6 ) (2 )
Segment margin related to ownership percentage in Ranch JV   3     1  
Adjusted Gathering and Processing Segment Margin 166 107
 
Natural Gas Transportation Segment Margin - -
 
Contract Services Segment Margin * 56 47
 
Corporate Segment Margin 5 5
 
Natural Resources Segment Margin 2 -
 
Inter-segment Elimination * (4 ) (3 )
   
Adjusted Total Segment Margin $ 225   $ 156  
 
* Inter-segment elimination is related to Contract Services segment margin.
 
Operating Data
Gathering and Processing Segment
Throughput (MMbtu/d) 2,662,000 1,990,000
NGL gross production (Bbls/d) 101,000 82,700
 
Natural Resources Segment
Coal royalty tonnage * 472,000 -
 
Contract Services Segment
Revenue generating horsepower 1,120,000 891,000
 
* Represents coal royalty tonnage for the period from March 21, 2014 (the acquisition date) to March 31, 2014.
 
 

Reconciliation of “distributable cash flow” to net cash flows provided by operating activities and to net income

     
Three Months Ended March 31,
  2014       2013  
($ in millions)
Net Cash Flows Provided by Operating Activities $ 187 $ 83
Add (deduct):
Depreciation, depletion and amortization, including debt issuance cost amortization and bond premium write-off and amortization (97 ) (67 )
Income from unconsolidated affiliates 43 35
Derivative valuation change (17 ) (18 )
Gain (loss) on asset sales, net 2 (1 )
Unit-based compensation expenses (2 ) (2 )
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related party receivables 21 14
Other current assets and other current liabilities (35 ) (85 )
Trade accounts payable and related party payables (48 ) 47
Distributions of earnings received from unconsolidated affiliates (43 ) (36 )
Cash flow changes in other assets and liabilities   1     1  
Net Income (Loss) $ 12   $ (29 )
Add:
Interest expense, net 56 37
Depreciation, depletion and amortization 94 65
Income tax benefit   (1 )   (2 )
EBITDA $ 161   $ 71  
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA 75 63
Income from unconsolidated affiliates (43 ) (35 )
Non-cash loss from commodity and embedded derivatives 4 18
Other, net   8     3  
Adjusted EBITDA $ 205   $ 120  
Add (deduct):
Interest expense, excluding capitalized interest (86 ) (42 )
Maintenance capital expenditures (25 ) (7 )
SUGS Contribution Agreement adjustment * - 21
PVR DCF Contribution 83 -
Proceeds from asset sales 5 12
Other adjustments   -     (3 )
Distributable cash flow $ 182   $ 101  
 
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
 

Contacts

Investor Relations:
Regency Energy Partners
Lyndsay Hannah
Manager, Finance & Investor Relations
214-840-5477
ir@regencygas.com
or
Media Relations:
Granado Communications Group
Vicki Granado
214-599-8785
vicki@granadopr.com

Release Summary

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the first-quarter ended March 31, 2014.

Sharing

Contacts

Investor Relations:
Regency Energy Partners
Lyndsay Hannah
Manager, Finance & Investor Relations
214-840-5477
ir@regencygas.com
or
Media Relations:
Granado Communications Group
Vicki Granado
214-599-8785
vicki@granadopr.com