Regency Energy Partners Reports Third Quarter 2012 Earnings Results

  Regency Energy Partners Reports Third Quarter 2012 Earnings Results

Business Wire

DALLAS -- November 07, 2012

Regency Energy Partners LP (NYSE: RGP), (“Regency” or the “Partnership”),
announced today its financial results for the third quarter ended September
30, 2012.

Adjusted EBITDA increased to $114 million in the third quarter of 2012,
compared to $112 million in the third quarter of 2011. The increase in
adjusted EBITDA was primarily due to an increase in adjusted total segment
margin primarily related to volume growth in the gathering and processing
segment, partially offset by higher operations and maintenance expenses.

In the third quarter of 2012, Regency generated $68 million in cash available
for distribution, compared to $73 million in the third quarter of 2011. This
decrease was primarily due to higher maintenance capital expenditures in the
third quarter of 2012 compared to the prior period. Regency had a net loss of
$2 million for the three months ended September 30, 2012, compared to the net
income of $30 million for the three months ended September 30, 2011, primarily
due to non-cash valuation adjustments recorded in each respective period.

“Volumes continued to increase in the third quarter, primarily in south and
west Texas, as well as in north Louisiana,” said Mike Bradley, president and
chief executive officer of Regency. “Results were impacted by temporary
operational issues and unplanned outages in our gathering and processing
segment and in our Lone Star Joint Venture; however we did see an uptick in
our contract services business which has begun to benefit from growth in
wet-gas regions.”

“Looking ahead, we remain excited about our portfolio of organic growth
projects. We believe the impact of these projects coming online will provide
Regency with additional earnings and volume growth throughout 2013,” said
Bradley.

REVIEW OF SEGMENT PERFORMANCE

Adjusted total segment margin increased to $116 million for the third quarter
of 2012, compared to $111 million for the third quarter of 2011.

Gathering and Processing – The Partnership provides “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
pipeline-quality natural gas and NGLs to various markets and pipeline systems.
This segment now includes the Partnership's investment in the Ranch Joint
Venture, which processes natural gas delivered from the NGLs-rich Bone Spring
and Avalon shale formations in west Texas. In June 2012, the Ranch Joint
Venture’s refrigeration processing plant became operational.

Adjusted segment margin for the Gathering and Processing segment, which
excludes non-cash gains and losses from commodity derivatives, was $68 million
for the third quarter of 2012, compared to $65 million for the third quarter
of 2011. The increase was primarily due to volume growth in south and west
Texas, and north Louisiana, which was partially offset by temporary
operational issues and plant downtime.

Total throughput volumes for the Gathering and Processing segment increased to
1.5 million MMbtu per day of natural gas for the third quarter of 2012,
compared to 1.3 million MMbtu per day of natural gas for the third quarter of
2011. Processed NGLs increased to 36,000 barrels per day for the third quarter
of 2012, compared to 35,000 barrels per day for the third quarter of 2011.

Joint Ventures – The Joint Ventures segment consists of a 49.99% interest in
the Haynesville Joint Venture, a 50% interest in the MEP Joint Venture and a
30% interest in the Lone Star Joint Venture. Since Regency uses the equity
method of accounting for these joint ventures, Regency does not record segment
margin for the Joint Ventures segment. Rather, the income attributable to each
of the joint ventures is recorded as income from unconsolidated affiliates.

The Haynesville Joint Venture consists solely of the Regency Intrastate Gas
System and is operated by Regency. Income from unconsolidated affiliates for
the Haynesville Joint Venture was $2 million for the third quarter of 2012,
compared to $11 million for the third quarter of 2011. This decrease is
primarily due to a non-cash asset impairment charge related to surplus
equipment of $7 million. Total throughput volumes for the Haynesville Joint
Venture averaged 0.8 million MMbtu per day of natural gas for the third
quarter of 2012, compared to 1.2 million MMbtu per day for the third quarter
of 2011.

The MEP Joint Venture consists solely of the Midcontinent Express Pipeline
(“MEP”) and is operated by Kinder Morgan Energy Partners, L.P. Income from
unconsolidated affiliates for the MEP Joint Venture was $10 million for the
third quarter of 2012 and $11 million for the third quarter of 2011. Total
throughput volumes for the MEP Joint Venture averaged 1.4 million MMbtu per
day of natural gas for the third quarter of 2012 and 1.3 million MMbtu per day
for the third quarter of 2011.

The Lone Star Joint Venture, which was acquired in May 2011, owns and operates
NGL storage, fractionation and transportation assets and is operated by Energy
Transfer Partners, L.P. For the third quarter of 2012, income from
unconsolidated affiliates for the Lone Star Joint Venture was $9 million,
compared to $9 million for the third quarter of 2011. Results for the third
quarter of 2012 were impacted by temporary downtime in the refinery services
segment due to Hurricane Isaac. For the third quarter of 2012, total
throughput volumes for the West Texas Pipeline averaged 132,000 barrels per
day, compared to 133,000 barrels per day for the third quarter of 2011 and NGL
Fractionation throughput volumes averaged 11,000 barrels per day in the third
quarter of 2012, compared to 14,000 barrels per day in the third quarter of
2011.

Contract Compression – The Contract Compression segment provides turn-key
natural gas compression services for customer-specific systems. Segment margin
for the Contract Compression segment, including both revenues from external
customers as well as intersegment revenues, was $39 million for the third
quarter of 2012, compared to $38 million for the third quarter of 2011. The
increase in segment margin is primarily due to the increase in revenue
generating horsepower, inclusive of intersegment revenue generating
horsepower. As of September 30, 2012, the Contract Compression segment’s
revenue generating horsepower, including intersegment revenue generating
horsepower, increased to 873,000, compared to 836,000 as of September 30,
2011. The increase in revenue generating horsepower is primarily attributable
to additional horsepower placed into service in south Texas for the Gathering
and Processing segment to provide compression services to external customers.

Contract Treating – The Partnership owns and operates a fleet of equipment
used to provide treating services, such as carbon dioxide and hydrogen sulfide
removal, natural gas cooling, dehydration and BTU management to natural gas
producers and midstream pipeline companies.

Segment margin for the Contract Treating segment was $8 million for the third
quarter of 2012, compared to $7 million for the third quarter of 2011. As of
September 30, 2012, revenue generating gallons per minute was 3,910, compared
to 3,468 as of September 30, 2011.

Corporate and Others – The Corporate and Others segment comprises a small
regulated pipeline and the Partnership’s corporate offices. Segment margin in
the Corporate and Others segment was $5 million for both the third quarter of
2012 and the third quarter of 2011.

ORGANIC GROWTH

In the nine months ended September 30, 2012, Regency incurred $557 million of
growth capital expenditures: $251 million for the Joint Ventures segment, $194
million for the Gathering and Processing segment, $81 million for the Contract
Compression segment and $31 million for the Contract Treating segment.

In the nine months ended September 30, 2012, Regency incurred $26 million of
maintenance capital expenditures.

In 2012, Regency expects to invest $820 million in growth capital
expenditures, of which $380 million is related to the Lone Star Joint Venture;
$300 million is related to the Gathering and Processing segment, which
includes expenditures related to the Ranch Joint Venture; $100 million related
to the Contract Compression segment; and $40 million related to the Contract
Treating segment.

In addition, Regency expects to make $32 million in maintenance capital
expenditures in 2012, including its proportionate share related to joint
ventures.

In 2013, Regency expects to invest approximately $400 million in growth
capital expenditures, of which $185 million is related to the Gathering and
Processing segment; $120 million related to the Lone Star Joint Venture; $80
million related to the Contract Compression segment; and $15 million related
to the Contract Treating segment.

In addition, Regency expects to invest $35 million in maintenance capital
expenditures in 2013, including its proportionate share related to joint
ventures.

CASH DISTRIBUTIONS

On October 25, 2012, Regency announced a cash distribution of $0.46 per
outstanding common unit for the third quarter ended September 30, 2012. This
distribution is equivalent to $1.84 per outstanding common unit on an annual
basis and will be paid on November 14, 2012, to unitholders of record at the
close of business on November 6, 2012.

Based on the terms of the partnership agreement, the Series A Preferred Units
will be paid a quarterly distribution of $0.445 per unit for the third quarter
ended September 30, 2012, on the same schedule as set forth above.

In the third quarter of 2012, Regency generated $68 million in cash available
for distribution, representing 0.83 times the amount required to cover its
announced distribution to unitholders. Year-to-date 2012, Regency generated
$242 million in cash available for distribution, representing 0.99 times the
amount required to cover its announced distribution to unitholders.

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, timing of organic growth projects and its internal forecasts of
adjusted EBITDA and cash available for distribution over an extended period.
Distributions are set 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
third-quarter 2012 results Thursday, November 8, 2012 at 10 a.m. Central Time
(11 a.m. Eastern Time).

The dial-in number for the call is 1-866-730-5766 in the United States, or
+1-857-350-1590 outside the United States, passcode 64826534. 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 40673746. 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, net, income tax
expense 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 expenses;
  *loss (gain) on asset sales, net;
  *loss on debt refinancing, net;
  *other non-cash (income) expense, net;
  *net income attributable to noncontrolling interest; 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.

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 cash available for distribution 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.

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 us 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 calculate our Gathering and Processing segment margin and Corporate and
Others segment margin as our revenues generated from operations less the cost
of natural gas and NGLs purchased and other cost of sales, including
third-party transportation and processing fees.

We do not record segment margin for the Joint Ventures segment because we
record our ownership percentage of the net income in these joint ventures as
income from unconsolidated affiliates in accordance with the equity method of
accounting.

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

We calculate our Contract Treating segment margin as revenues generated from
our contract treating operations minus direct costs associated with those
revenues.

We calculate total segment margin as the total 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, including intersegment eliminations. Adjusted segment margin and
adjusted total segment margin are included as supplemental disclosures because
they are primary performance measures used by management because they
represent the results of product purchases and sales, a key component of our
operations.

FORWARD-LOOKING INFORMATION AND OTHER DISCLAIMERS

This release includes “forward-looking” statements. Forward-looking statements
are identified as any statement that does not relate strictly to historical or
current facts. Statements using words such as “anticipate,” “believe,”
“intend,” “project,” “plan,” “expect,” “continue,” “estimate,” “goal,”
“forecast,” “may” or similar expressions help identify forward-looking
statements. Although we believe our forward-looking statements are based on
reasonable assumptions and current expectations and projections about future
events, we cannot give any assurance that such expectations will prove to be
correct. Forward-looking statements are subject to a variety of risks,
uncertainties and assumptions. Additional risks include: volatility in the
price of oil, natural gas, and natural gas liquids, declines in the credit
markets and the availability of credit for the Partnership as well as for
producers connected to the Partnership’s system and its customers, the level
of creditworthiness of, and performance by the Partnership’s counterparties
and customers, the Partnership's ability to access capital to fund organic
growth projects and acquisitions, and the Partnership’s ability to obtain debt
and equity financing on satisfactory terms, 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, and
demand for the Partnership's services, changes in laws and regulations
impacting the midstream sector of the natural gas industry, weather and other
natural phenomena, industry changes including the impact of consolidations and
changes in competition, 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 statements.

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 Energy Partners LP (NYSE: RGP) is a growth-oriented, master limited
partnership engaged in the gathering and processing, contract compression,
contract treating and transportation of natural gas and the transportation,
fractionation and storage of natural gas liquids. Regency's general partner is
owned by Energy Transfer Equity, L.P. (NYSE: ETE). For more information,
please visit Regency’s website at www.regencyenergy.com.


Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in thousands)
(unaudited)
                                                          
                                        September 30, 2012   December 31, 2011
Assets
Current assets                          $     209,684        $    187,124
                                                             
Property, plant and equipment, net            2,059,196           1,885,528
                                                             
Investment in unconsolidated                  2,156,135           1,924,705
affiliates
Long-term derivative assets                   918                 474
Other assets, net                             33,486              39,353
Intangible assets, net                        718,928             740,883
Goodwill                                     789,789            789,789
Total Assets                            $     5,968,136      $    5,567,856
                                                             
Liabilities and Partners' Capital and
Noncontrolling Interest
Current liabilities                     $     214,107        $    233,306
                                                             
Long-term derivative liabilities              29,490              39,112
Other long-term liabilities                   5,550               6,071
Long-term debt                                1,960,429           1,687,147
                                                             
Series A Preferred Units                      72,549              71,144
                                                             
Partners' capital                             3,627,879           3,498,207
Noncontrolling interest                      58,132             32,869
Total Partners' Capital and                  3,686,011          3,531,076
Noncontrolling Interest
Total Liabilities and Partners'         $     5,968,136      $    5,567,856
Capital and Noncontrolling Interest
                                                                  
                                                                  

Regency Energy Partners LP
Condensed Consolidated Statements of Operations
($ in thousands)
(unaudited)
                                                           
                                             Three Months Ended September 30,
                                             2012              2011
                                                               
REVENUES                                     $ 313,882         $ 390,267
                                                               
OPERATING COSTS AND EXPENSES
Cost of sales, including related party         206,881           279,526
amounts
Operation and maintenance                      41,275            37,950
General and administrative, including          14,935            17,350
related party amounts
Gain on asset sales, net                       (42         )     (131        )
Depreciation and amortization                 45,881          41,956      
Total operating costs and expenses             308,930           376,651
                                                               
OPERATING INCOME                               4,952             13,616
                                                               
Income from unconsolidated affiliates          21,055            30,946
Interest expense, net                          (28,567     )     (28,852     )
Other income and deductions, net              1,106           15,050      
(LOSS) INCOME BEFORE INCOME TAXES              (1,454      )     30,760
Income tax expense (benefit)                  -               (89         )
NET (LOSS) INCOME                            $ (1,454      )   $ 30,849
Net income attributable to                    (379        )    (549        )
noncontrolling interest
NET (LOSS) INCOME ATTRIBUTABLE TO            $ (1,833      )   $ 30,300      
REGENCY ENERGY PARTNERS LP
                                                               
Limited partners' interest in net (loss)     $ (5,977      )   $ 26,243
income
Weighted average number of common units        170,264,621       145,842,735
outstanding
Basic (loss) income per common unit          $ (0.04       )   $ 0.18
Diluted (loss) income per common unit        $ (0.04       )   $ 0.09
                                                                             
                                                                             

Segment Financial and Operating Data

                                             Three Months Ended September 30,
                                              2012              2011
                                              ($ in thousands)
Gathering and Processing Segment
Financial data:
Segment margin                                $   59,392         $  64,716
Adjusted segment margin                           68,269            64,890
Operating data:
Throughput (MMbtu/d)                              1,461,122         1,292,766
NGL gross production (Bbls/d)                     36,338            34,847
                                              
                                              Three Months Ended September 30,
                                              2012               2011
                                              ($ in thousands)
Contract Compression Segment
Financial data:
Segment margin                                $   39,380         $  37,957
Operating data:
Revenue generating horsepower, including          872,776           836,094
intercompany revenue generating horsepower
                                              
                                              Three Months Ended September 30,
                                              2012               2011
                                              ($ in thousands)
Contract Treating Segment
Financial data:
Segment margin                                $   8,115          $  6,642
Operating data:
Revenue generating gallons per minute             3,910             3,468
                                                                 
                                              Three Months Ended September 30,
                                              2012               2011
                                              ($ in thousands)
Corporate & Others
Financial data:
Segment margin                                $   5,459          $  4,767
                                                                    
                                                                    

The following provides key performance measures for 100% of the Haynesville
Joint Venture, the MEP Joint Venture and the Lone Star Joint Venture


                                         Three Months Ended September 30,
                                          2012              2011
                                          ($ in thousands)
Haynesville Joint Venture
Financial data:
Segment margin                            $   42,187         $  43,583
Operating data:
Throughput (MMbtu/d)                          826,974           1,192,203
                                                             
                                          Three Months Ended September 30,
                                          2012               2011
                                          ($ in thousands)
MEP Joint Venture
Financial data:
Segment margin                            $   61,126         $  61,925
Operating data:
Throughput (MMbtu/d)                          1,391,605         1,320,480
                                                             
                                          Three Months Ended September 30,
                                          2012               2011
                                          ($ in thousands)
Lone Star Joint Venture
Financial data:
Segment margin                            $   63,709         $  65,372
Operating data:
West Texas Pipeline Throughput (Bbls/d)       132,297           133,149
NGL Fractionation Throughput (Bbls/d)         11,073            13,833
                                                                
                                                                

The following provides a reconciliation of segment margin to net income for
100% of the Haynesville Joint Venture, the MEP Joint Venture and the Lone Star
Joint Venture

                                                             
                                              Three Months Ended September 30,
                                              2012               2011
Haynesville Joint Venture                     ($ in thousands)
Net income                                    $   6,520          $  24,282
Add:
Operation and maintenance                         5,482             5,509
General and administrative                        5,177             4,348
Depreciation and amortization                     9,152             9,100
Interest expense, net                             457               395
Impairment of property, plant and equipment       14,114            -
Other income and deductions, net                 1,285           (51     )
Total Segment Margin                          $   42,187        $  43,583  
                                                                 
                                              Three Months Ended September 30,
                                              2012               2011
MEP Joint Venture                             ($ in thousands)
Net income                                    $   20,735         $  21,998
Add:
Operating expenses                                10,225            9,672
Depreciation and amortization                     17,354            17,401
Interest expense, net                             12,816            12,849
Other income and deductions, net                 (4       )       5       
Total Segment Margin                          $   61,126        $  61,925  
                                              
                                              Three Months Ended September 30,
                                              2012               2011
Lone Star Joint Venture                       ($ in thousands)
Net income                                    $   30,611         $  30,952
Add:
Operation and maintenance                         14,788            16,575
General and administrative                        4,960             4,958
Depreciation and amortization                     12,833            12,904
Tax expense                                       641               11
Other income and deductions, net                 (124     )       (28     )
Total Segment Margin                          $   63,709        $  65,372  
                                                                            
                                                                            

Reconciliation of Non-GAAP Measures to GAAP Measures

                                            
                                              Three Months Ended September 30,
                                              2012             2011
                                              ($ in thousands)
Net (loss) income                             $  (1,454   )     $  30,849
Add (deduct):
Interest expense, net                            28,567            28,852
Depreciation and amortization                    45,881            41,956
Income tax benefit                              -               (89      )
EBITDA (1)                                    $  72,994         $  101,568
Add (deduct):
Non-cash loss (gain) from commodity and          7,327             (15,056  )
embedded derivatives
Unit-based compensation expenses                 1,176             891
Loss on asset sales, net                         (42      )        (131     )
Income from unconsolidated affiliates            (21,055  )        (30,946  )
Partnership's interest in unconsolidated         54,201            56,128
affiliates' adjusted EBITDA (2)(3)(4)(5)
Other income, net                               (379     )       (178     )
Adjusted EBITDA                               $  114,222       $  112,276  
                                                                
(1) Earnings before interest, taxes,
depreciation and amortization.
                                                                
(2) 100% of Haynesville Joint Venture's
Adjusted EBITDA and the Partnership's
interest are calculated as follows:
Net income Haynesville Joint Venture          $  6,520          $  24,282
Add (deduct):
Depreciation and amortization                    9,152             9,100
Interest expense, net                            457               395
Impairment of property, plant and equipment      14,114            -
Other expense, net                              1,285           5        
Haynesville Joint Venture's Adjusted EBITDA   $  31,528         $  33,782
Ownership interest                              49.99    %       49.99    %
Partnership's interest in Haynesville Joint   $  15,761        $  16,885   
Venture's Adjusted EBITDA
                                                                
(3) 100% of MEP Joint Venture's Adjusted
EBITDA and the Partnership's interest are
calculated as follows:
Net income MEP Joint Venture                  $  20,735         $  21,998
Add:
Depreciation and amortization                    17,354            17,401
Interest expense, net                            12,816            12,855
Other income                                    (4       )       -        
MEP Joint Venture's Adjusted EBITDA           $  50,901         $  52,254
Ownership interest                              50       %       49.90    %
Partnership's interest in MEP Joint           $  25,450        $  26,091   
Venture's Adjusted EBITDA
                                                                
(4) 100% of Lone Star Joint Venture's
Adjusted EBITDA and the Partnership's
interest are calculated as follows:
Net income Lone Star Joint Venture            $  30,611         $  30,952
Add (deduct):
Depreciation and amortization                    12,832            12,904
Other expenses, net                             36              (16      )
Lone Star Joint Venture's Adjusted EBITDA     $  43,479         $  43,840
Ownership interest                              30       %       30       %
Partnership's interest in Lone Star Joint     $  13,045        $  13,152   
Venture's Adjusted EBITDA
                                                                
(5) 100% of Ranch Joint Venture's Adjusted
EBITDA and the Partnership's interest are
calculated as follows:
Net loss Ranch Star Joint Venture             $  (880     )        N/A
Add (deduct):
Depreciation and amortization                   713             N/A      
Ranch Joint Venture's Adjusted EBITDA         $  (167     )        N/A
Ownership interest                              33       %       N/A      
Partnership's interest in Ranch Joint         $  (55      )       N/A      
Venture's Adjusted EBITDA
We acquired a 33.33% interest in the Ranch
Joint Venture in December 2011.
                                                                
                                                                

Reconciliation of Non-GAAP Measures to GAAP Measures

                                             
                                               Nine Months Ended September 30,
                                               2012             2011
                                               ($ in thousands)
Net income                                     $  56,773         $  59,991
Add (deduct):
Interest expense, net                             86,058            73,548
Depreciation and amortization                     142,519           122,695
Income tax expense (benefit)                     89              (19      )
EBITDA (1)                                     $  285,439        $  256,215
Add (deduct):
Non-cash gain from commodity and embedded         (16,650  )        (20,149  )
derivatives
Unit-based compensation expenses                  3,470             2,687
Loss on asset sales, net                          1,542             50
Loss on debt refinancing, net                     7,820             -
Income from unconsolidated affiliates             (87,198  )        (86,921  )
Partnership's interest in unconsolidated          170,582           156,000
affiliates' adjusted EBITDA (2)(3)(4)(5)
Other income, net                                (1,462   )       (413     )
Adjusted EBITDA                                $  363,543       $  307,469  
                                                                 
(1) Earnings before interest, taxes,
depreciation and amortization.
                                                                 
(2) 100% of Haynesville Joint Venture's
Adjusted EBITDA and the Partnership's
interest are calculated as follows:
Net income Haynesville Joint Venture           $  55,364         $  84,703
Add (deduct):
Depreciation and amortization                     27,354            25,846
Interest expense, net                             1,397             782
Impairment of property, plant and equipment       14,114            -
Other expense, net                               1,285           16       
Haynesville Joint Venture's Adjusted EBITDA    $  99,514         $  111,347
Ownership interest                               49.99    %       49.99    %
Partnership's interest in Haynesville Joint    $  49,747          55,660   
Venture's Adjusted EBITDA
                                                                 
(3) 100% of MEP Joint Venture's Adjusted
EBITDA and the Partnership's interest are
calculated as follows:
Net income MEP Joint Venture                   $  62,606         $  62,684
Add:
Depreciation and amortization                     52,075            52,176
Interest expense, net                             38,609            38,623
Other income                                     (4       )       -        
MEP Joint Venture's Adjusted EBITDA            $  153,286        $  153,483
Ownership interest                               50       %       49.90    %
Partnership's interest in MEP Joint            $  76,643          76,604   
Venture's Adjusted EBITDA
                                                                 
(4) 100% of Lone Star Joint Venture's
Adjusted EBITDA and the Partnership's
interest are calculated as follows:
Net income Lone Star Joint Venture             $  109,712        $  58,910
Add (deduct):
Depreciation and amortization                     37,737            20,043
Other expenses, net                              36              169      
Lone Star Joint Venture's Adjusted EBITDA      $  147,485        $  79,122
Ownership interest                               30       %       30       %
Partnership's interest in Lone Star Joint      $  44,246          23,736   
Venture's Adjusted EBITDA
We acquired a 30% interest in the Lone Star
Joint Venture in May 2011.
                                                                 
(5) 100% of Ranch Joint Venture's Adjusted
EBITDA and the Partnership's interest are
calculated as follows:
Net loss Ranch Joint Venture                   $  (931     )     $  -
Add (deduct):
Depreciation and amortization                    768             -        
Ranch Joint Venture's Adjusted EBITDA          $  (163     )     $  -
Ownership interest                               33       %       0        %
Partnership's interest in Ranch Joint          $  (54      )     $  -        
Venture's Adjusted EBITDA
We acquired a 33.33% interest in the Ranch
Joint Venture in December 2011.
                                                                 
                                                                 

Non-GAAP Adjusted Total Segment Margin to GAAP Net Income

                                                            
                                              Three Months Ended September 30,
                                              2012              2011
                                              ($ in thousands)
Net income                                    $  (1,454   )     $  30,849
Add (deduct):
Operation and maintenance                        41,275            37,950
General and administrative                       14,935            17,350
Loss on asset sales, net                         (42      )        (131     )
Depreciation and amortization                    45,881            41,956
Income from unconsolidated affiliates            (21,055  )        (30,946  )
Interest expense, net                            28,567            28,852
Other income and deductions, net                 (1,106   )        (15,050  )
Income tax expense (benefit)                    -               (89      )
Total Segment Margin                             107,001           110,741
Non-cash loss from commodity derivatives        8,877           174      
Adjusted Total Segment Margin                 $  115,878       $  110,915  
                                                                
Gathering & Processing Segment Margin         $  59,392         $  64,716
Non-cash loss from commodity derivatives        8,877           174      
Adjusted Gathering and Processing Segment        68,269            64,890
Margin
                                                                
Contract Compression Segment Margin              39,380            37,957
                                                                
Contract Treating Segment Margin                 8,115             6,642
                                                                
Corporate & Others Segment Margin                5,459             4,767
                                                                
Inter-segment Eliminations                       (5,345   )        (3,341   )
                                                               
Adjusted Total Segment Margin                 $  115,878       $  110,915  
                                                                            
                                                                            

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

                                            
                                              Three Months Ended September 30,
                                              2012             2011
                                              ($ in thousands)
Net cash flows provided by operating          $  78,729         $  83,302
activities
Add (deduct):
Depreciation and amortization, including
debt issuance cost, bond premium and excess      (47,554  )        (43,492  )
fair value of unconsolidated affiliates
amortization
Income from unconsolidated affiliates            21,055            30,946
Derivative valuation change                      (7,326   )        15,834
(Loss) gain on asset sales, net                  42                131
Unit-based compensation expenses                 (1,176   )        (697     )
Cash flow changes in current assets and
liabilities:
Trade accounts receivables, accrued              10,273            4,451
revenues, and related party receivables
Other current assets                             1,608             778
Trade accounts payable, accrued cost of gas
and liquids, related party payables and          (20,228  )        8,110
deferred revenues
Other current liabilities                        (8,135   )        (27,597  )
Distributions received from unconsolidated       (28,797  )        (40,796  )
affiliates
Other assets and liabilities                    55              (121     )
Net (Loss) Income                             $  (1,454   )     $  30,849   
Add:
Interest expense, net                            28,567            28,852
Depreciation and amortization                    45,881            41,956
Income tax benefit                              -               (89      )
EBITDA                                        $  72,994        $  101,568  
Add (deduct):
Non-cash gain (loss) from commodity and          7,327             (15,056  )
embedded derivatives
Unit-based compensation expenses                 1,176             891
Loss on asset sales, net                         (42      )        (131     )
Income from unconsolidated affiliates            (21,055  )        (30,946  )
Partnership's interest in unconsolidated         54,201            56,128
affiliates' adjusted EBITDA
Other income, net                               (379     )       (178     )
Adjusted EBITDA                               $  114,222       $  112,276  
Add (deduct):
Interest expense, excluding capitalized          (33,962  )        (35,092  )
interest
Maintenance capital expenditures                 (11,170  )        (7,002   )
Proceeds from asset sales                        2,118             6,258
Distribution to Series A Preferred Units         (1,946   )        (1,945   )
Other adjustments                               (1,578   )       (1,249   )
Cash available for distribution               $  67,684        $  73,246   
                                                                            
                                                                            

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

                                                              
                                               Nine Months Ended September 30,
                                               2012               2011
                                               ($ in thousands)
Net cash flows provided by operating           $  180,925         $ 204,416
activities
Add (deduct):
Depreciation and amortization, including          (146,913  )       (127,079 )
debt issuance cost and bond premium
Income from unconsolidated affiliates             87,198            86,921
Derivative valuation change                       17,124            21,660
Loss on asset sales, net                          (1,542    )       (50      )
Unit-based compensation expenses                  (3,470    )       (2,444   )
Cash flow changes in current assets and
liabilities:
Trade accounts receivables, accrued               (10,779   )       13,298
revenues, and related party receivables
Other current assets                              1,429             (186     )
Trade accounts payable, accrued cost of gas
and liquids, related party payables and           31,675            (20,467  )
deferred revenues
Other current liabilities                         (7,159    )       (24,833  )
Distributions received from unconsolidated        (91,893   )       (91,306  )
affiliates
Other assets and liabilities                     178             61       
Net Income                                     $  56,773         $ 59,991   
Add:
Interest expense, net                             86,058            73,548
Depreciation and amortization                     142,519           122,695
Income tax expense (benefit)                     89              (19      )
EBITDA                                         $  285,439        $ 256,215  
Add (deduct):
Non-cash gain from commodity and embedded         (16,650   )       (20,149  )
derivatives
Unit-based compensation expenses                  3,470             2,687
Loss on asset sales, net                          1,542             50
Loss on debt refinancing, net                     7,820             -
Income from unconsolidated affiliates             (87,198   )       (86,921  )
Partnership's interest in unconsolidated          170,582           156,000
affiliates' adjusted EBITDA
Other income, net                                (1,462    )      (413     )
Adjusted EBITDA                                $  363,543        $ 307,469  
Add (deduct):
Interest expense, excluding capitalized           (110,165  )       (91,367  )
interest
Maintenance capital expenditures                  (25,625   )       (13,776  )
Proceeds from asset sales                         22,528            10,242
Distribution to Series A Preferred Units          (5,836    )       (5,835   )
Other adjustments                                (2,810    )      (3,961   )
Cash available for distribution                $  241,635        $ 202,772  

Contact:

Regency Energy Partners
Investor Relations:
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
 
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