INSERTING and REPLACING Regency Energy Partners Reports Increased Full-Year 2013 Adjusted EBITDA

DALLAS--()--Insert in Condensed Consolidated Statements of Operations three months ended and full year ended tables the line item for Cost of Sales.

The corrected release reads:

Regency Energy Partners Reports Increased Full-Year 2013 Adjusted EBITDA

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”), announced today its financial results for the fourth-quarter and full-year ended December 31, 2013.

The results presented herein have been retrospectively adjusted to combine Regency’s results with the results of Southern Union Gathering Company (“SUGS”) beginning March 26, 2012, due to the as-if pooling accounting treatment required for an acquisition between commonly controlled entities.

For full-year 2013, adjusted EBITDA increased 18 percent to $608 million compared to $517 million in 2012, primarily due to volume growth in the gathering and processing segment, and in the Lone Star JV, as well as an increase in revenue generating horsepower in the contract services segment.

For the year-ended December 31, 2013, Regency generated $411 million in cash available for distribution, compared to $310 million for full-year 2012. Distributable cash flow excludes any impact related to the historical SUGS results.

Net income decreased to $19 million for the year ended December 31, 2013, compared to $32 million for the year ended December 31, 2012. This decrease was primarily due to an increase in depreciation and amortization, an increase in operations and maintenance expense, and an increase in interest expense, partially offset by an increase in total segment margin, all related to our organic growth projects and a full year of the SUGS operations.

“In 2013, we completed the acquisition and integration of the SUGS assets, and brought online a significant amount of organic growth projects which, along with increased drilling activity, contributed to strong growth in our gathering and processing and NGL logistics businesses,” said Mike Bradley, president and chief executive officer of Regency. “In addition, improved demand for compression services led to a nearly 20 percent increase in revenue generating horsepower.”

“For 2014, we expect strong earnings and volume growth across our base business driven by our substantial organic growth program in 2012 and 2013,” continued Bradley. “In addition, we expect the recently acquired Hoover midstream assets, and the proposed acquisitions of PVR Partners and Eagle Rock’s midstream business to provide additional growth opportunities, particularly in the Marcellus and Utica Shales in the northeast, the Granite Wash in the Mid-continent and the Permian Basin in west Texas.”

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased 21 percent to $729 million for the full-year 2013, compared to $602 million for full-year 2012.

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. This segment also includes our 33.33% membership interest in Ranch JV, which processes natural gas delivered from the NGLs-rich Bone Spring and Avalon shale formations in west Texas.

Adjusted segment margin for the Gathering and Processing segment, which excludes non-cash gains and losses from commodity derivatives, was $522 million for full-year 2013, compared to $412 million for full-year 2012. The increase was primarily due to volume growth in south and west Texas, and north Louisiana.

Total throughput volumes for the Gathering and Processing segment increased to 2.1 million MMbtu per day of natural gas for full-year 2013, compared to 1.8 million MMbtu per day of natural gas for full-year 2012. Processed NGLs increased to 90,000 barrels per day for the full-year 2013, compared to 69,000 barrels per day for full-year 2012.

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 $204 million for full-year 2013, compared to $189 million for full-year 2012. The increase in segment margin is primarily due to the increase in revenue generating horsepower, inclusive of intersegment revenue generating horsepower. As of December 31, 2013, the Contract Compression segment’s revenue generating horsepower, including intersegment revenue generating horsepower, increased to 1,049,000, compared to 884,000 as of December 31, 2012, inclusive of 44,000 and 96,000, respectively of revenue generating horsepower utilized by the gathering and processing segment.

Corporate – The Corporate segment comprises our corporate offices. Segment margin in the Corporate segment was $18 million for full-year 2013 compared to $20 million for full-year 2012.

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 $30 million for full-year 2013, compared to $29 million for full-year 2012. This increase was primarily due to the absence of a non-cash asset impairment charge related to surplus equipment offset by the expiration of certain contracts. Total throughput volumes for HPC averaged 648,000 MMbtu per day of natural gas for full-year 2013, compared to 854,000 MMbtu per day for full-year 2012.

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 $40 million for full-year 2013 and $42 million for full-year 2012. Total throughput volumes for the MEP Joint Venture averaged 1.3 million MMbtu per day of natural gas for full-year 2013 and 1.4 million MMbtu per day for full-year 2012.

NGL Services – We own a 30% membership interest in Lone Star, an entity owning a diverse set of midstream energy assets including pipelines, 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 $64 million for full-year 2013 and $44 million for full-year 2012. Transportation volumes averaged 164,000 barrels per day for the year ended December 31, 2013, compared to 134,000 barrels per day for the year ended December 31, 2012. Refinery Services throughput averaged 13,000 barrels per day for the year ended December 31, 2013, compared to 17,000 barrels per day for the year ended December 31, 2012. NGL Fractionation volumes for the first two fractionators, which came online in December 2012 and November 2013, respectively, averaged 78,000 barrels per day for the year ended December 31, 2013.

ORGANIC GROWTH

For the year ended December 31, 2013, Regency incurred $948 million of growth capital expenditures: $550 million for the Gathering and Processing segment, $270 million for the Contract Services segment, $123 million for the NGL Services segment and $5 million for the Corporate segment.

For the year ended December 31, 2013, Regency incurred $48 million of maintenance capital expenditures.

In 2014, Regency expects to invest approximately $540 million in growth capital expenditures, of which $230 million is related to the Gathering and Processing segment, inclusive of expenditures related to the recently acquired Hoover midstream business; $200 million is related to the Contract Services segment and $110 million is related to the NGL Services segment.

In addition, Regency expects to invest $60 million in maintenance capital expenditures in 2014, including its proportionate share related to joint ventures.

CASH DISTRIBUTIONS

On January 28, 2014, Regency announced a cash distribution of $0.475 per outstanding common unit for the fourth-quarter ended December 31, 2013. This distribution is equivalent to $1.90 per outstanding common unit on an annual basis and was paid on February 14, 2013, to unitholders of record at the close of business on February 7, 2013.

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 fourth-quarter ended December 31, 2013, on the same schedule as set forth above.

For full-year 2013, Regency generated $411 million in distributable cash flow, representing 1.01 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 fourth-quarter and full-year 2013 results Thursday, February 20, 2013, at 10 a.m. Central Time (11 a.m. Eastern Time).

The dial-in number for the call is 1-866-202-3048 in the United States, or +1-617-213-8843 outside the United States, passcode 57429927. 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 90089019. 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 and Ranch JV) 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. 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. 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, 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)
   
 
December 31, 2013   December 31, 2012
Assets
Current assets $ 400 $ 340
Property, plant and equipment, net 4,418 3,686
Investment in unconsolidated affiliates 2,097 2,214
Other assets, net 57 43
Intangible assets, net 682 712
Goodwill   1,128   1,128
Total Assets $ 8,782 $ 8,123
 
Liabilities and Partners' Capital and Noncontrolling Interest
Current liabilities $ 475 $ 489
Other long-term liabilities 49 64
Long-term debt   3,310   2,157
Total Liabilities $ 3,834 $ 2,710
 
Series A Preferred Units 32 73
 
Partners' capital 4,814 3,530
Member's equity - 1,733
Noncontrolling interest   102   77
Total Partners' Capital and Noncontrolling Interest   4,916   5,340
Total Liabilities and Partners' Capital and Noncontrolling Interest $ 8,782 $ 8,123
 

Consolidated Statements of Operations

     
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
 
Three Months Ended December 31,
  2013     2012     2011  
 
REVENUES $ 677 $ 587 $ 370
 
OPERATING COSTS AND EXPENSES

Cost of Sales

484

 428

258

Operation and maintenance 76 69 42
General and administrative 24 22 14
Gain on asset sales, net 1 1 (2 )
Depreciation and amortization   80     59     46  
Total operating costs and expenses 665 579 358
 
OPERATING INCOME 12 8 12
Income from unconsolidated affiliates 32 18 33
Interest expense, net (45 ) (36 ) (29 )
Other income and deductions, net   3     3     (3 )
INCOME (LOSS) BEFORE INCOME TAXES 2 (7 ) 13
Income tax benefit   -     1     (1 )
NET INCOME (LOSS) $ 2 $ (8 ) $ 14
Net income attributable to noncontrolling interest   (3 )   -     (1 )
NET INCOME (LOSS) ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ (1 ) $ (8 ) $ 13  
 
Amount allocated to common units $ (6 ) $ (14 ) $ 9
Weighted average number of common units outstanding 210,747,732 170,841,959 155,675,662
Basic (loss) income per common unit $ (0.03 ) $ (0.08 ) $ 0.06
Diluted (loss) income per common unit $ (0.03 ) $ (0.08 ) $ 0.06
 

Consolidated Statements of Operations

     
Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in millions)
 
Year Ended
  2013     2012     2011  
 
REVENUES $ 2,521 $ 2,000 $ 1,434
 
OPERATING COSTS AND EXPENSES

Cost of Sales

1,793

1,387

1,013

Operation and maintenance 296 228 147
General and administrative 88 100 67
Loss (gain) on asset sales, net 2 3 (2 )
Depreciation and amortization   287     252     169  
Total operating costs and expenses 2,466 1,970 1,394
 
OPERATING INCOME 55 30 40
Income from unconsolidated affiliates 135 105 120
Interest expense, net (164 ) (122 ) (103 )
Loss on debt refinancing, net (7 ) (8 ) -
Other income and deductions, net   7     29     17  
INCOME BEFORE INCOME TAXES 26 34 74
Income tax benefit   (1 )   -     -  
NET INCOME $ 27 $ 34 $ 74
Net income attributable to noncontrolling interest   (8 )   (2 )   (2 )
NET INCOME ATTRIBUTABLE TO REGENCY ENERGY PARTNERS LP $ 19   $ 32   $ 72  
 
Amount allocated to common units $ 34 $ 27 $ 57
Weighted average number of common units outstanding 196,227,348 167,492,735 145,490,869
Basic income per common unit $ 0.17 $ 0.16 $ 0.39
Diluted income per common unit $ 0.17 $ 0.13 $ 0.32
 

Segment Financial and Operating Data

  Three Months Ended December 31,   Year Ended December 31,
  2013     2012     2011   2013     2012     2011
Gathering and Processing Segment
Financial data:
Segment margin $ 138 $ 109 $ 64 $ 521 $ 423 $ 233
Adjusted segment margin 142 109 62 522 412 229
Operating data:
Throughput (MMbtu/d) 2,216,000 2,008,000 1,350,000 2,141,000 1,793,000 1,187,000
NGL gross production (Bbls/d) 92,000 83,000 36,000 90,000 69,000 32,000
  Three Months Ended December 31,   Year Ended December 31,
  2013     2012     2011   2013     2012     2011
Contract Services
Financial data:
Segment margin $ 55 $ 50 $ 47 $ 204 $ 189 $ 185
Operating data:
Revenue generating horsepower, including intercompany revenue generating horsepower 1,049,000 884,000 844,800 1,049,000 884,000 846,000
  Three Months Ended December 31,   Year Ended December 31,
2013   2012   2011 2013   2012   2011
 
Corporate Segment
Financial data:
Segment margin $ 4 $ 6 $ 4 $ 18 $ 20 $ 17
 

Reconciliation of Non-GAAP Measures to GAAP Measures

         
Three Months Ended December 31,
  2013     2012     2011  
($ in millions)
Net Income (Loss) $ 2 $ (8 ) $ 14
Add (deduct):
Interest expense, net 45 36 29
Depreciation and amortization 80 59 46
Income tax benefit   -     1     (1 )
EBITDA (1) $ 127 $ 88 $ 88
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2) 62 52 57
Income from unconsolidated affiliates (32 ) (18 ) (33 )
Non-cash loss (gain) from commodity and embedded derivatives 3 (2 ) 2
Other, net   5     1     (1 )
Adjusted EBITDA $ 165   $ 121   $ 113  
(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 September 30, 2013 and 2012:
               
Three months ended December 31, 2013
HPC   MEP   Lone Star   Ranch JV   Grey Ranch   Total
Net Income (Loss) $ 16 $ 17 $ 54 $ 2 $ (1 )
Add:
Depreciation and amortization 9 17 24 1 -
Interest expense, net   3     13     -     -     -  
Adjusted EBITDA   28     47     78     3     (1 )
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 14   $ 24   $ 23   $ 1   $ -   $ 62
 
Operating data
Throughput (MMbtu/d) 524,000 1,271,000 N/A 96,000 N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 170,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 9,000 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A 103,000 N/A N/A
 
Three months ended December 31, 2012
HPC   MEP   Lone Star   Ranch JV   Grey Ranch   Total
Net Income (Loss) $ 14 $ 22 $ 37 $ (1 ) $ (18 )
Add:
Depreciation and amortization 9 17 14 1 -
Interest expense, net 1 13 - - -
Impairment of property, plant, and equipment   8     -     -     -     8  
Adjusted EBITDA   32     52     51     -     (10 )
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 16   $ 26   $ 15   $ -   $ (5 ) $ 52
 
Operating data
Throughput (MMbtu/d) 748,000 1,397,000 N/A 5,200 N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 137,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 17,700 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A - N/A N/A
 
Three months ended December 31, 2011
HPC   MEP   Lone Star Ranch JV Grey Ranch Total
Net Income $ 24 $ 23 $ 35 $ - $ -
Add:
Depreciation and amortization 9 17 12 - -
Interest expense, net   -     13     -     -     -  
Adjusted EBITDA   33     53     47     -     -  
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 16   $ 27   $ 14   $ -   $ -   $ 57
 
Operating data
Throughput (MMbtu/d) 1,054,000 1,380,000 N/A - N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 127,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 18,000 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A - N/A N/A
 
(1) Includes Gateway Pipeline throughput which was placed in service in December 2012.
(2) Fractionator began operations in December 2012.
 

Reconciliation of Non-GAAP Measures to GAAP Measures

         
Year ended December 31,
  2013     2012     2011  
($ in millions)
Net Income $ 27 $ 34 $ 74
Add (deduct):
Interest expense, net 164 122 103
Depreciation and amortization 287 252 169
Income tax benefit   (1 )   -     -  
EBITDA (1) $ 477 $ 408 $ 346
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA (2) 250 222 213
Income from unconsolidated affiliates (135 ) (105 ) (120 )
Non-cash loss (gain) from commodity and embedded derivatives 3 (19 ) (18 )
Loss on debt refinancing, net 7 8 -
Loss (gain) on asset sales, net 2 3 (2 )
Other, net   4     -     1  
Adjusted EBITDA $ 608   $ 517   $ 420  
(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 nine months ended September 30, 2013 and 2012:
               
Year ended December 31, 2013
HPC   MEP   Lone Star   Ranch JV   Grey Ranch   Total
Net Income (Loss) $ 72 $ 80 $ 214 $ 4 $ (1 )
Add:
Depreciation and amortization 37 69 84 5 -
Interest expense, net 5 51 - - -
Other expenses, net   -     -     2     -     -  
Adjusted EBITDA   114     200     300     9     (1 )
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 57   $ 100   $ 90   $ 3   $ -   $ 250
 
Operating data
Throughput (MMbtu/d) 648,000 1,315,000 N/A 73,000 N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 164,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 13,000 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A 78,000 N/A N/A
 
Year ended December 31, 2012
HPC   MEP   Lone Star   Ranch JV   Grey Ranch   Total
Net Income (Loss) $ 70 $ 83 $ 147 $ (2 ) $ (18 )
Add:
Depreciation and amortization 36 69 52 1 -
Interest expense, net 2 52 - - -
Impairment of property, plant, and equipment 22 - - - 8
Other expenses, net   2     -     -     -     -  
Adjusted EBITDA   132     204     199     (1 )   (10 )
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 65   $ 102   $ 60   $ -   $ (5 ) $ 222
 
Operating data
Throughput (MMbtu/d) 854,000 1,409,000 N/A 3,300 N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 134,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 17,000 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A - N/A N/A
 
Year ended December 31, 2011
HPC   MEP   Lone Star   Ranch JV   Grey Ranch   Total
Net Income $ 109 $ 85 $ 94 $ - $ -
Add:
Depreciation and amortization 35 70 32 - -
Interest expense, net   1     51     -     -     -  
Adjusted EBITDA   145     206     126     -     -  
Ownership interest   49.99 %   50 %   30 %   33.33 %   50 %  
Partnership's interest in Adjusted EBITDA $ 72   $ 103   $ 38   $ -   $ -   $ 213
 
Operating data
Throughput (MMbtu/d) 1,321,000 1,361,000 N/A N/A N/A
NGL Transportation - Throughput (Bbls/d) (1) N/A N/A 130,000 N/A N/A
Refinery - Throughput (Bbls/d) N/A N/A 15,700 N/A N/A
Fractionation - Throughput (Bbls/d) (2) N/A N/A - N/A N/A
 
(1) Includes Gateway Pipeline throughput which was placed in service in December 2012.
(2) Fractionator began operations in December 2012.
 

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

  Three Months Ended December 31,
2013   2012   2011
Net Income (Loss) $ 2 $ (8 ) $ 14
Add (Deduct):
Operation and maintenance 76 69 42
General and administrative 24 22 14
Loss (gain) on asset sales, net 1 1 (2 )
Depreciation and amortization 80 59 46
Income from unconsolidated affiliates (32 ) (18 ) (33 )
Interest expense, net 45 36 29
Other income and deductions, net (3 ) (3 ) 3
Income tax expense (benefit)   -     1     (1 )
Total Segment Margin 193 159 112
Non-cash gain (loss) from commodity derivatives 7 2 (1 )
Segment margin related to the noncontrolling interest (5 ) (2 ) (1 )
Segment margin related to ownership percentage in Ranch JV   2     -     -  
Adjusted Total Segment Margin $ 197   $ 159   $ 110  
Gathering & Processing Segment Margin $ 138 $ 109 $ 64
Non-cash gain (loss) from commodity derivatives 7 2 (1 )
Segment margin related to the noncontrolling interest (5 ) (2 ) (1 )
Segment margin related to ownership percentage in Ranch JV   2     -     -  
Adjusted Gathering and Processing Segment Margin 142 109 62
 
Natural Gas Transportation Segment Margin - - 1
 
Contract Services Segment Margin * 55 50 47
 
Corporate Segment Margin 4 6 4
 
Inter-segment Elimination * (4 ) (6 ) (4 )
     
Adjusted Total Segment Margin $ 197   $ 159   $ 110  
 
* Inter-segment elimination is related to Contract Services segment margin.
 

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

  Year Ended December 31,
2013   2012   2011
Net Income $ 27 $ 34 $ 74
Add (Deduct):
Operation and maintenance 296 228 147
General and administrative 88 100 67
Loss (gain) on asset sales, net 2 3 (2 )
Depreciation and amortization 287 252 169
Income from unconsolidated affiliates (135 ) (105 ) (120 )
Interest expense, net 164 122 103
Loss on debt refinancing, net 7 8 -
Other income and deductions, net (7 ) (29 ) (17 )
Income tax benefit   (1 )   -     -  
Total Segment Margin 728 613 421
Non-cash loss (gain) from commodity derivatives 9 (5 ) -
Segment margin related to the noncontrolling interest (13 ) (6 ) (4 )
Segment margin related to ownership percentage in Ranch JV   5     -     -  
Adjusted Total Segment Margin $ 729   $ 602   $ 417  
Gathering & Processing Segment Margin $ 521 $ 423 $ 233
Non-cash gain (loss) from commodity derivatives 9 (5 ) -
Segment margin related to the noncontrolling interest (13 ) (6 ) (4 )
Segment margin related to ownership percentage in Ranch JV   5     -     -  
Adjusted Gathering and Processing Segment Margin 522 412 229
 
Natural Gas Transportation Segment Margin - 2 3
 
Contract Services Segment Margin 204 189 185
 
Corporate Segment Margin * 18 20 17
 
Inter-segment Elimination * (15 ) (21 ) (17 )
     
Adjusted Total Segment Margin $ 729   $ 602   $ 417  
 
* Inter-segment elimination is related to Contract Services segment margin.
 

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

       
Three Months Ended December 31,
  2013       2012       2011  
Net Cash Flows Provided by Operating Activities $ 59 $ 68 $ 49
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization and bond premium write-off and amortization (82 ) (62 ) (48 )
Income from unconsolidated affiliates 32 18 33
Derivative valuation change (3 ) 2 (1 )
(Loss) gain on asset sales, net (1 ) (1 ) 2
Unit-based compensation expenses (2 ) (2 ) (1 )
Cash flow changes in current assets and liabilities:
Other current assets and other current liabilities 28 43 15
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues (20 ) (51 ) (3 )
Distributions of earnings received from unconsolidated affiliates (33 ) (29 ) (28 )
Other assets and liabilities   1     (3 )   1  
Net Income (Loss) $ 2   $ (8 ) $ 14  
Add:
Depreciation and amortization 80 59 46
Income tax benefit (expense)   -     1     (1 )
EBITDA $ 127   $ 88   $ 88  
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted EBITDA 62 52 58
Income from unconsolidated affiliates (32 ) (18 ) (33 )
Non-cash loss (gain) from commodity and embedded derivatives 3 (2 ) 2
Other, net   5     1     (2 )
Adjusted EBITDA $ 165   $ 121   $ 113  
Add (deduct):
Interest expense, excluding capitalized interest (51 ) (41 ) (35 )
Maintenance capital expenditures (18 ) (8 ) (8 )
SUGS Contribution Agreement adjustment * - (4 ) -
Proceeds from asset sales 2 4 -
Other adjustments   (4 )   (4 )   12  
Distributable cash flow $ 94   $ 68   $ 82  
 
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
 

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

       
Year ended December 31,
2013   2012 2011
Net Cash Flows Provided by Operating Activities $ 436 $ 324 $ 254
Add (deduct):
Depreciation and amortization, including debt issuance cost amortization and bond premium write-off and amortization (293 ) (259 ) (175 )
Income from unconsolidated affiliates 135 105 120
Derivative valuation change (6 ) 12 21
Loss (gain) on asset sales, net (2 ) (3 ) 2
Unit-based compensation expenses (7 ) (5 ) (3 )
Cash flow changes in current assets and liabilities:
Other current assets and other current liabilities 54 (10 ) (11 )
Trade accounts payable, accrued cost of gas and liquids, related party payables and deferred revenues (119 ) (18 ) (23 )
Distributions of earnings received from unconsolidated affiliates (142 ) (121 ) (119 )
Other assets and liabilities   (125 )   9     -  
Net Income $ 27   $ 34   $ 74  
Add:
Depreciation and amortization 287 252 169
Income tax benefit   (1 )   -     -  
EBITDA $ 477   $ 408   $ 346  
Add (deduct):
Non-cash loss (gain) from commodity and embedded derivatives 3 (19 ) (18 )
Loss on debt refinancing, net 7 8 -
Income from unconsolidated affiliates (135 ) (105 ) (120 )
Partnership's interest in unconsolidated affiliates' adjusted EBITDA 250 222 213
Other, net   6     3     (1 )
Adjusted EBITDA $ 608   $ 517   $ 420  
Add (deduct):
Interest expense, excluding capitalized interest (192 ) (151 ) (113 )
Maintenance capital expenditures (48 ) (34 ) (20 )
SUGS Contribution Agreement adjustment * 34 (37 ) -
Proceeds from asset sales 18 27 10
Other adjustments   (9 )   (12 )   (12 )
Distributable cash flow $ 411   $ 310   $ 285  
 
* 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, 214-840-5477
Manager, Finance & Investor Relations
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 fourth-quarter and full-year ended December 31, 2013.

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Contacts

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