425

Filed by Regency Energy Partners LP pursuant

to Rule 425 under the Securities Act of 1933 and

deemed filed pursuant to Rule 14a-12 of the Securities

Exchange Act of 1934.

Subject Company: PVR Partners, L.P.

Commission File No.: 001-16735

IMPORTANT ADDITIONAL INFORMATION WILL BE FILED WITH THE SEC

INVESTORS AND SECURITY HOLDERS ARE URGED TO READ THE PROXY STATEMENT/PROSPECTUS AND THE REGISTRATION STATEMENT REGARDING THE TRANSACTION CAREFULLY WHEN THEY ARE AVAILABLE. These documents (when they become available), and any other documents filed by PVR or Regency with the Securities and Exchange Commission (the “SEC”), may be obtained free of charge at the SEC’s website, at www.sec.gov. In addition, security holders will be able to obtain free copies of the proxy statement/prospectus (when available) from PVR by contacting Investor Relations by mail at Attention: Investor Relations, Three Radnor Corporate Center, Suite 301, 100 Matsonford Road, Radnor, Pennsylvania 19087.

PARTICIPANTS IN THE SOLICITATION

Regency and PVR, and their respective directors and executive officers, may be deemed to be participants in the solicitation of proxies in respect of the transactions contemplated by the Agreement and Plan of Merger. Information regarding the directors and executive officers of Regency GP LLC, the general partner of Regency’s general partner, is contained in Regency’s Form 10-K for the year ended December 31, 2012, which has been filed with the SEC. Information regarding PVR’s directors and executive officers is contained in PVR’s Form 10-K for the year ended December 31, 2012 and its proxy statement filed on April 25, 2013, which are filed with the SEC. A more complete description will be available in the Registration Statement and the Proxy Statement/Prospectus.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

Statements in this document regarding the proposed transaction between Regency and PVR, the expected timetable for completing the proposed transaction, future financial and operating results, benefits and synergies of the proposed transaction, future opportunities for the combined company and any other statements about Regency’s or PVR’s management’s future expectations, beliefs, goals, plans or prospects constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that are not statements of historical fact (including statements containing the words “believes,” “plans,” “anticipates,” “expects,” “estimates” and similar expressions) should also be considered to be forward-looking statements.

Regency and PVR cannot give any assurance that expectations and projections about future events will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. These risks and uncertainties include the risks that the proposed transaction may not be consummated or the benefits contemplated therefrom may not be realized. Additional risks include: the ability to obtain requisite regulatory and unitholder approval and the satisfaction of the other conditions to the consummation of the proposed transaction, the ability of Regency to successfully integrate PVR’s operations and employees and realize anticipated synergies and cost savings, the potential impact of the announcement or consummation of the proposed transaction on relationships, including with employees, suppliers, customers, competitors and credit rating agencies, the ability to achieve revenue, DCF and EBITDA growth, volatility in the price of oil, natural gas, and natural gas liquids, declines in the credit markets and the availability of credit for the combined company as well as for producers connected to the combined company’s system and its customers, the level of creditworthiness of, and performance by counterparties and customers, the ability to access capital to fund organic growth projects and acquisitions, including significant acquisitions, and the ability to obtain debt and equity financing on satisfactory terms, the use of derivative financial instruments to hedge commodity and interest rate risks, the amount of collateral required to be posted from time-to-time, changes in commodity prices, interest rates, and demand for the combined company’s services, changes in laws and regulations impacting the midstream sector of the natural gas industry, weather and other natural phenomena, acts of terrorism and war, industry changes including the impact of consolidations and changes in competition, the ability to obtain required approvals for construction or modernization of facilities and

 

1


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 Regency and PVR with the SEC, which are available to the public. Regency and PVR undertake no obligation to update publicly or to revise any forward-looking statements, whether as a result of new information, future events or otherwise.

*****

 

2


Regency Energy Partners LP
Wells Fargo MLP Conference
December 10 -
11, 2013


Forward-Looking Statements
2
Certain matters discussed in this report include “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 assurances 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 information.
In light of these risks, uncertainties and assumptions, the events described in the forward-looking statements
might not occur or might occur to a different extent or at a different time than the Partnership has described. The
Partnership undertakes no obligation to update publicly or to revise any forward-looking statements, whether as
a result of new information, future events or otherwise.


Adjusted EBITDA increased 50% and DCF increased 67% over
Legacy third quarter 2012 results, respectively³
Average volumes for the third quarter of 2013 increased by
more than 50% and NGL production increased 166%,
compared to third quarter 2012 volumes
Lone Star’s NGL Transportation throughput increased 30%
compared to the third quarter of 2012
Revenue generating horsepower reached an all-time high
Key 2013 Highlights
3
1
Via Lone Star Joint Venture
2
Including assumption of net debt
3
Third quarter 2012 adjusted EBITDA results exclude SUGS
In September, announced public offering of $400 million of
5.75% Senior Notes due 2020
Had approximately $1 billion of available liquidity at the end
of the third quarter
Pro forma leverage ratio of 4.1x as of 9/30/2013
Completed the acquisition of SUGS in May, and integration is
substantially complete
Completed construction of 209,000 Bbls/d Gateway NGL
Pipeline and first two 100,000 Bbls/d Mont Belvieu
fractionators¹
Added more than 410 MMcf/d of processing capacity and 150
MMcf/d of treating capacity via organic growth projects
Completed projects continue ramp up in 2014
Creates a leading gathering and processing footprint in key,
high-growth plays in the United States with a strong platform
for additional growth
Adds a strong growth platform in the Marcellus and Utica
Shales  and significantly expands Regency’s position in the
Midcontinent
Expect approximately $30 million in synergies per year
Anticipate project cash flows will contribute to significant
increase in DCF and EBITDA over time
Further Strengthened Balance Sheet
Announced Plans to Purchase PVR Partners for $5.6 Billion²
Delivered solid financial and operating performance,
driven by increased volumes in liquids-rich regions   
Completed more than $3 billion of major, organic growth
projects and acquisitions in the last 12 months


4
Expanding Asset Base
1
As of 9/30/12 and 9/30/2013, respectively
2
2012 throughput does  not include SUGS
3
Via Haynesville Joint Venture, in which Regency has  a 49.99% interest, and MEP Joint Venture, in which Regency has a 50% interest; also includes Gulf States Transmission, a 10-mile interstate pipeline that extends from
Harrison County, Texas to Caddo Parish, Louisiana
4
Via Lone Star Joint Venture, in which Regency has a 30% interest
Diversified asset portfolio is strategically positioned to benefit from drilling activity in liquids-rich plays
Asset Summary
2012¹
2013¹
Gathering Pipeline (miles)
6,345
11,945
Gathering and Processing
Throughput
(Mmbtu/d)
2
1.4 million
2.2 million
Treating/Processing Plants
11
19
Processing Capacity (MMcf/d)
695
1,600
Transportation Pipeline
(miles)
3
960
960
Contract Compression (HP)
873,000
1,014,000
NGL
Transportation
(miles)
4
1,170
1,740
NGL
Fractionation
(Bbls/d)
4
25,000
225,000
47
47
Eagle Ford 
Increased capacity of  Eagle Ford
Expansion Project by 125 MMcf/d
and added  150 MMcf/d of treating
capacity
Permian
Acquired SUGS and completed
125 MMcf/d Ranch JV facility
Haynesville/Cotton Valley 
Added 90 MMcf/d of
processing capacity
Midcontinent
Granite Wash
Mississippi Lime
Marcellus
Utica
NGL
Storage
(MMBbls/d)
4


5
Gathering & Processing: West Texas
Year-Over-Year Growth¹
Total volumes increased 410% over Legacy Q3 2012
NGL production increased 690% over Legacy Q3 2012
SUGS system integration complete
Processing capacity increased from 125 MMcf/d to   
940 MMcf/d
Recently completed 140 MMcf/d of gathering
expansions into Reeves County (Delaware Basin)
2014 Opportunities
Currently constructing 125 MMcf/d of additional
gathering capacity into Andrews and Culberson counties
(Delaware Basin)
Plans to add 200 MMcf/d of incremental processing
capacity in early 2015
Expanding condensate stabilization and transportation
systems
1
Comparison is third quarter 2012 versus third quarter 2013; third quarter 2012 results exclude SUGS
Red Bluff Expansion
Ranch JV Expansion


6
Gathering & Processing: South Texas
Year-Over-Year Growth¹
Total South Texas volumes have increased nearly 40%
Total NGL production has increased nearly 40%
Eagle Ford Expansion Project volumes have increased
60%
Increased total treating capacity from 170 MMcf/d to
320 MMcf/d
Added 17,000 Bbls/d of oil gathering capacity
2014 Opportunities
Continued volume ramp up across all systems
Pursuing approximately 70,000 Bbls/d of crude
gathering
Expect to further increase treating capacity
1
Comparison is third quarter 2012 versus third quarter 2013; third quarter 2012 results exclude SUGS
Eagle Ford Expansion
Edwards Lime
Expansion
Tilden
Expansion


7
Gathering & Processing: North Louisiana
Dubach
Expansion
Dubberly
Expansion
2014 Opportunities
Completing construction of 400 MMcf/d of additional
gathering capacity by January 1, 2014
Completing 200 MMcf/d processing upgrade at Dubberly
Planning to add 100 MMcf/d of gathering capacity
Evaluating new cryogenic processing expansion at
Dubberly
Growth from Cotton Valley expected to bring new
volumes to RIGS
1
Comparison is third quarter 2012 versus third quarter 2013; third quarter 2012 results exclude SUGS
Dubach volumes have increased more than 60%
Dubach NGL production has increased more than 50%
Increased processing capacity from 140 MMcf/d to
210 MMcf/d
Built 22 miles of high-pressure gathering pipeline with a
capacity of 100 MMcf/d


8
Lone Star Opportunities
Expect Lone Star’s EBITDA to increase significantly as projects come online and volumes
ramp up in 2014 and 2015
West Texas Gateway NGL
Pipeline
Frac 1 & 2
Mariner
South
209,000 Bbls/d Gateway Pipeline in service and began
ramp up
Announced 6 million Bbls/month LPG export facility
(In service 2015)
Continued volume ramp up on Gateway and Fracs I and II
Permitting 100,000 Bbls/d Frac III
Evaluating expansion of NGL transportation capacity from
Permian Basin
Opportunities to expand downstream transportation
infrastructure and NGL purity product markets
Year-Over-Year Growth
2014
Opportunities
Added
200,000
Bbls/d
of
Fractionation
Capacity
(Frac
II
came
online
November
2013)


Contract Services Opportunities
New opportunities driving increased capex spending for compression due to continued strong
demand, particularly in the Permian Basin, Eagle Ford, Niobrara and Appalachian Shales
Contract Compression Growth Opportunities
As of November 1
st
, have approximately
50,000 HP booked to be set for the
remainder of 2013
Larger gas-lift opportunities and turn-key
facility installations, including for
compression and production facilities,  will
drive growth in the Eagle Ford and Permian
100,000
HP
potential
Oil and liquids activity is increasing Utica
Shale
opportunities
for
2014
40,000
HP
potential
Expect additional growth in the Niobrara
Shale as customers  solidify expansion plans
40,000
HP
potential
Other
20,000
HP
potential
9
Barnett/Haynesville
Marcellus/Utica
Niobrara
Fayetteville
Permian/Avalon/
Bone Spring
Granite Wash
Gulf Coast
Eagle Ford


Overview of PVR
Partners Acquisition


Strategic Highlights
Combination of Regency and PVR creates a premiere, diversified gas gathering and processing MLP with
scaled presence in the most economic, high-growth, oil and gas plays in North America
Increased Scale  and
Basin Diversification
PVR
adds
a
strategic
presence
in
three
prolific
areas;
the
Marcellus
and
Utica
Shales
in
the
Appalachian 
Basin, and the Granite Wash in the Mid-Continent
Meaningful Growth
Projects
PVR has several projects under development or construction
which are expected to add significant
volumes in 2015
Announced Utica Ohio River Project will provide a substantial growth opportunity with in-service date
early 2015
‘First-mover’
advantage
Significant upside
Acquisition of Largely
Fee-Based EBITDA
Stable contracted, fee-based asset portfolio with a majority of PVR gross margin under fixed-fee
contracts
Marcellus expected to comprise ~55% of PVR EBITDA in 2013E
and is all fee-based; significant demand
charges on trunklines
Enhanced Long-Term  
Value Creation
Significant increase in EBITDA and DCF expected over time as the combined company benefits from
project cash flows
Estimate achieving synergies of approximately $30 million per year (beginning in year 1)
Transaction and pro forma credit profile is in keeping with Regency long-term investment grade rating
objective
11
Combination strengthens Regency’s position for long-term distribution growth


12
Expanding Asset Base
Pro Forma Asset Base
PVR combination will expand Regency’s position in the major growth plays in the lower 48
Expands reach into
Cline Shale
Greatly expands
Midcontinent
into Granite Wash
Mississippi Lime
Adds major position in
Marcellus and
Utica Shales
1
As of 9/30/13
2
Operated within Regency’s Gathering & Processing Segment
3
Via Haynesville Joint Venture, in which Regency has  a 49.99% interest, and MEP Joint Venture, in which Regency has a 50% interest; also includes Gulf States Transmission, a 10-mile interstate pipeline that extends from
Harrison County, Texas to Caddo Parish, Louisiana
4
Via Lone Star Joint Venture, in which Regency has a 30% interest
Announced Utica Ohio
River Project
¹
Gathering Pipeline (miles)
16,738
Treating/Processing Plants
25
Transportation Pipeline (miles)
960
Contract Compression (HP)
1,014,000
NGL Transportation (miles)
1,740
NGL Fractionation (Bbls/d)
225,000
NGL Storage
(MMBbls/d)
47
Pro Forma Asset Summary
4
4
2
3
4


13
Marcellus Productivity: Finding the Sweet Spots
Source: U.S. Capital Advisors
Indicates county in which PVR has operations in service
Indicates county in which PVR has acreage dedications/systems under development
PVR’s assets sit in most of the top producing counties in the Marcellus Shale


Marcellus Productivity Rankings
Source: U.S. Capital Advisors
Marcellus EUR Scatter by County
PVR has assets in 6 of the 10 counties generating the highest EURs in the Marcellus Shale
Indicates county in which PVR has operations
14


Summary
15
Extensive
midstream
portfolio
and
strong
position
in
majority
of
high-growth
shale
plays
driving
expansion opportunities
Strong Visibility for
Continued Growth
High-Quality Assets
Integrated Midstream
Platform
Focused on Execution
Completed $3+ billion in
organic  projects and
acquisitions with continued
ramp up in 2014 and beyond
PVR acquisition will add
considerable scale and
significant growth
opportunities, which supports
long-term distribution growth
New organic growth
opportunities continue to
develop across all operating
areas
Assets strategically located in
majority of the most prolific
shale plays and basins
Strong position in oil and
liquids-rich plays driving
significant organic growth
program
High percentage of fee-based
margins
Comprehensive midstream
service provider with
significant presence across
the midstream value chain
Diversity of business mix,
large scale, along with
strategically located assets
enhances stability of cash
flows
SUGS integration
substantially complete
PVR integration plan
underway
Continue to develop and
execute organic projects on
time and within budget
Maintain strong balance
sheet and financial flexibility
Regency is well positioned for long-term distribution growth


Appendix


17
Recently Completed Expansions
1.
Represents Regency’s 33.33% share
2.
Represents Regency’s 30% share
3.
Represents Regency’s 60% share
4.
Represents total project costs. Regency's expected costs since April 30, 2013 are expected to be $69 million
Project
RGP Growth Capital
($ in millions)
Estimated Completion Date
Expected Ramp Up
Ranch
JV
Processing
Facility
1
$33
Refrigeration Plant –June 2012
Cryogenic Processing Plant –
Operational December 2012
Currently operating at 75% capacity; 100% contracted
under firm contracts
Lone
Star
Gateway
NGL
Pipeline
2
$275
December 2012
Expect volumes to continue to continue to increase in
2014 and 2015
Lone
Star
Fractionator
1
2
$118
December 2012
Throughput reached 72,000 Bbls/d for Q3 2013; 100%
contracted
Tilden Treating Plant Expansion
$40
January 2013
Volumes have increased more than 40% since the
expansion came online in January 2013
Dubach Expansion
$75
JT Plant –November 2012
Cryogenic Processing Plant –June 2013
Legacy and expanded cryogenic operating at 100%
capacity
Red
Bluff
Expansion
4
$330
In service August 2013
Currently flowing at 70% of capacity which will
increase  with new gathering tie ins  and additional
expansion  planned for the area
Edwards Lime  JV Gathering
System
Expansion
3
$90
Online Q3 2013
Increased capacity of the treating facility by nearly
45%  and  Q3 2013 volumes have increased 28% over
Q3  2012
Added 17,000 Bbls/d oil gathering system that
is  currently flowing 10,000 Bbls/d
Lone
Star
Fractionator
2
2
$105
Q4 2013
Expect volumes to tier up into 2015
Eagle Ford Expansion
$490
Ongoing; Final Completion Early 2014
Build out 90% complete; Moving over 400 million a day,
handling three-phase flow of oil, gas and water
Total Growth Capital
$1,556


100% fee-based:
Firm reservation charges provide a floor on returns
Additional volumetric fees based upon actual volumes
Gathering Pipeline / Trunkline Miles: 252
Well Connects: 261 (through July 31, 2013)
2013 Q2 Volume (MMcfd): 1,310
377,000+ dedicated acres with substantial producers committed
to development
Fresh water pipeline JV supplies producers
In May 2012, PVR acquired a membership interests of Chief
Gathering LLC resulting in a major expansion of its pipeline
systems in the Eastern Midstream segment
Marcellus Systems Overview
NY
PA
PVR Eastern Midstream Overview
First large-diameter gathering system in north-central PA Marcellus
fairway
80 miles of 30-inch pipeline
850 MMcf/d capacity
Phase I began service Q1 2011
Phase II began service Q4 2011
Phase III began service Q4 2012
Total well connects of 125 through July 31, 2013
Lycoming System
Trunkline nature of the system provides bi-directional flows to
Transco and Tennessee Gas; adds optionality for producers and
effectively doubles capacity on the line
Running through Wyoming Co., PA enables access to 4 market
outlets via 2 major pipelines
Began service June 2010
89 miles of 24-inch pipeline in service since Q4 2012
750 MMcf/d capacity
Currently constructing system extension to service additional local
producers
Total well connects of 51 through July 31, 2013
Wyoming System
Asset Map
18


PVR Mid-Continent Midstream Overview
Key Highlights
Midcontinent Assets
Traditional midstream gathering and
processing business
Assets are located in attractive
natural gas basins with long-lived
reserves
460 MMcfd processing capacity
Hamlin and Crescent systems
positioned for growth in Cline Shale
and Mississippi Lime, respectively
19
Gathering Pipeline Miles: 4,541
Plants and Processing Capacity: 6
plants (460 MMcfd)
Key Statistics


1
Excludes corporate, eliminations and Gulf State contributions
2
Represents revenue from segment
3
Includes both gathering and processing and transportation
4
Includes Eastern and Mid-Continent PVR segments
2013E Gross Margin
20
Improvements to Regency & PVR Business Profile
Pro Forma
Regency
1
PVR
2,3
3
2
3,4
G&P
48%
Contract Services
20%
Nat. Gas
Trans.
20%
NGL Services
12%
Eastern
46%
Mid-
Continent
30%
Coal
24%
G&P
57%
Contract Services
Nat. Gas Trans.
14%
NGL Services
8%
Coal
7%
14%


21
Maintain Stable Cash Flows: DCF Sensitivities
1
As of November 22, 2013
Regency
has
length
in
natural
gas
due
to
a
concerted
effort
to
minimize
‘keep-whole’
exposure
A $10.00 per Bbl movement in crude along with the same percentage change in NGL pricing would result in a
$12 million change in Regency’s forecasted 2014 DCF
A $1.00 per MMbtu movement in natural gas pricing would result in a $20 million change in Regency’s
forecasted 2014 DCF   
DCF
Sensitivity
to
Commodity
Price
Changes
2014
Decrease $10.00
Flat
Increase $10.00
Decrease $1.00
$ 32M
$ 20M
$ 8M
Flat
$ 12M
$ 0
$ (12)M
Increase $1.00
$ (8)M
$ (20)M
$(32)M
Change in WTI Price ($/Bbl)


22
Maintain Stable Cash Flows: Comprehensive Hedging Program
1
As of November 22, 2013.  Based on exposures as of Q3 2013
Executed Hedges by Product¹
Balance of 2013
Full Year 2014
Natural Gas/Ethane
41%
51%
Propane
84%
66%
Normal Butane
54%
67%
C5+/Condensate
82%
49%


23
Maintain Stable Cash Flows: Comprehensive Hedging Program
1
As of October 16, 2013
Executed Hedges by Product
¹
Balance of 2013
Full Year 2014
Bbls/d
Price
($/gal)
Bbls/d
Price
($/gal)
Propane
3,150
$0.96
2,500
$1.01
Normal Butane
975
$1.38
1,200
$1.39
Bbls/d
Price
($/Bbl)
Bbls/d
Price
($/Bbl)
WTI
2,365
$97.08
1,426
$92.70
Cushing to Midland Basis
1,000
(0.35)
-
-
MMbtu/d
Price
($/MMbtu)
MMbtu/d
Price
($/MMbtu)
Natural Gas (Henry Hub)
23,000
$3.92
32,000
$3.96
Natural Gas (Permian)
15,000
$4.35
15,000
$4.22


24
Non-GAAP Reconciliation
1
Beginning in the second quarter of 2013, results have been retrospectively adjusted to combine Regency’s results with SUGS results due to the as-if pooling accounting treatment required for an acquisition between
commonly controlled entities. Results shown prior to the second quarter of 2013 exclude any impact related to the historical SUGS results
September 30, 2013
June 30, 2013
March 31, 2013
December 31, 2012
September 30, 2012
June 30, 2012
March 31, 2012
Net income (loss)
42
11
(29)
$                 
(8)
$                          
(2)
$                          
28
$                         
15
$                         
Add:
Interest expense, net
41
41
37
                     
35
                           
29
                           
28
                           
30
                           
Depreciation and amortization
74
68
                     
65
                     
60
                           
71
                           
69
                           
53
                           
Income tax expense (benefit)
2
                               
0
(3)
                     
-
                              
(1)
                            
-
                              
-
                              
EBITDA (1)
159
$                         
120
$                 
70
$                   
87
$                         
97
$                         
125
$                       
98
$                         
Add (deduct):
Partnership's ownership interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)
66
                             
60
                     
63
                     
56
                           
54
                           
60
                           
57
                           
Income from unconsolidated affiliates
(37)
                           
(31)
                   
(35)
                   
(19)
                          
(20)
                          
(34)
                          
(32)
                          
Non-cash (gain) loss from commodity and embedded derivatives
(14)
                           
(4)
                     
18
                     
(2)
                            
7
                             
(22)
                          
(2)
                            
Loss on debt refinancing, net
-
                               
7
                       
-
                       
-
                              
-
                              
8
                             
-
                              
Other income, net
(2)
                             
3
                       
1
                       
2
                             
1
                             
1
                             
2
                             
Adjusted EBITDA
172
$                         
155
$                 
117
$                 
124
$                       
139
$                       
138
$                       
123
$                       
(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
18
$                           
18
$                   
20
$                   
14
$                         
7
$                           
26
$                         
23
$                         
Add (deduct):
Depreciation and amortization
9
                               
9
                       
9
                       
9
                             
9
                             
9
                             
9
                             
Interest expense, net
1
                               
-
                       
1
                       
1
                             
-
                              
1
                             
-
                              
Loss on sale of asset, net
-
                               
-
                       
-
                       
-
                              
1
                             
-
                              
-
                              
Impairment of property, plant and equipment
-
                               
-
                       
-
                       
8
                             
14
                           
-
                              
-
                              
Other expense, net
-
                               
-
                       
-
                       
1
                             
-
                              
-
                              
-
                              
Adjusted EBITDA
28
$                           
27
$                   
30
$                   
33
$                         
31
$                         
36
$                         
32
$                         
Ownership interest
49.99%
49.99%
49.99%
49.99%
49.99%
49.99%
49.99%
Partnership's interest in Adjusted EBITDA
14
$                           
13
$                   
15
$                   
15
$                         
15
$                         
18
$                         
16
$                         
(3) 100% of MEP Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income
21
$                           
21
$                   
21
$                   
21
$                         
21
$                         
21
$                         
21
$                         
Add:
Depreciation and amortization
17
                             
17
                     
18
                     
17
                           
17
                           
17
                           
17
                           
Interest expense, net
13
                             
13
                     
13
                     
13
                           
13
                           
13
                           
13
                           
Adjusted EBITDA
51
$                           
51
$                   
52
$                   
51
$                         
51
$                         
51
$                         
51
$                         
Ownership interest
50%
50%
50%
50%
50%
50%
50%
Partnership's interest in Adjusted EBITDA
26
$                           
26
$                   
26
$                   
26
$                         
26
$                         
26
$                         
26
$                         
We acquired a 49.9% interest in MEP Joint Venture in May 2010.
(4) 100% of Lone Star Joint Venture's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net income
60
$                           
44
$                   
55
$                   
37
$                         
31
$                         
41
$                         
38
$                         
Add (deduct):
Depreciation and amortization
21
                             
20
                     
20
                     
14
                           
13
                           
13
                           
12
                           
Other (income) expense, net
1
                               
1
                       
-
                   
-
                          
-
                          
(1)
                            
1
                             
Adjusted EBITDA
82
$                           
65
$                   
75
$                   
51
$                         
44
$                         
53
$                         
51
$                         
Ownership interest
30%
30%
30%
30%
30%
30%
30%
Partnership's interest in Adjusted EBITDA
25
$                           
20
$                   
23
$                   
15
$                         
13
$                         
16
$                         
15
$                         
We acquired a 30% interest in 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
1
$                             
1
$                     
-
$                     
(1)
$                          
(1)
$                          
-
$                            
-
$                            
Add (deduct):
Depreciation and amortization
1
                               
1
                       
2
                       
1
                             
-
                              
-
                              
-
                              
Adjusted EBITDA
2
$                             
2
$                     
2
$                     
-
$                            
(1)
$                          
-
$                            
-
$                            
Ownership interest
33%
33%
33%
33%
33%
33%
33%
Partnership's interest in Adjusted EBITDA
1
$                             
1
$                     
1
$                     
-
$                        
(0)
$                          
-
$                        
-
                          
We acquired a 33.33% interest in Ranch Joint Venture in December 2011.
($ in millions)
Three Months Ended


25
Non-GAAP Reconciliation
2013
2012
Ranch Joint Venture
Net income (loss)
1
$                    
(1)
$                   
Add:
Operation and maintenance
1
-
Depreciation and amortization
1
1
Total Segment Margin
3
$                    
-
$                    
Three Months Ended September 30,
($ in millions)
*Ranch Joint Venture's Refrigeration Processing Plant started its operation in June
2012 and the full facility began operations in December 2012.
2013
2012
Lone Star Joint Venture
Net income
61
$               
31
$                    
Add:
Operation and maintenance
21
15
General and administrative
8
5
Depreciation and amortization
21
13
Income tax expense
1
1
Total Segment Margin
112
$            
65
$                   
Three Months Ended September 30,
($ in millions)
2013
2012
MEP Joint Venture
Net income
21
$                  
21
$               
Add:
Operation and maintenance
4
4
General and administrative
6
6
Depreciation and amortization
17
17
Interest expense, net
13
13
Total Segment Margin
61
$                 
61
$              
Three Months Ended September 30,
($ in millions)
2013
2012
Haynesville Joint Venture
Net income
18
$                      
7
$                        
Add:
Operation and maintenance
5
5
General and administrative
4
5
Depreciation and amortization
9
9
Interest expense, net
1
14
Other income and deductions, net
-
1
Total Segment Margin
37
$                     
41
$                     
Three Months Ended September 30,
($ in millions)


26
Non-GAAP Reconciliation¹
September 2013
June 2013
March 2013
December 2012
September 2012
June 2012
March 2012
Net cash flows provided by operating activities
183
$                   
112
$        
67
$             
71
$                    
79
$                     
46
$         
56
$             
Add (deduct):
Depreciation and amortization, including debt issuance cost
amortization and bond premium write-off and amortization
(75)
                     
(68)
          
(50)
              
(62)
                    
(47)
                     
(45)
          
(54)
              
Income from unconsolidated affiliates
37
                      
31
           
35
               
27
                     
21
                      
33
           
32
               
Derivative valuation change
14
                      
1
              
(18)
              
2
                       
(7)
                       
22
           
3
                 
Loss on asset sales, net
2
                        
(1)
             
(1)
               
(1)
                      
-
                         
(2)
             
-
                 
Unit-based compensation expenses
(2)
                       
(1)
             
(2)
               
(1)
                      
(1)
                       
(1)
             
(1)
               
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related
party receivables
32
                      
27
           
8
                 
4
                       
10
                      
(14)
          
(7)
               
Other current assets and other current liabilities
(25)
                     
137
         
(13)
              
1
                       
(7)
                       
6
              
(5)
               
Trade accounts payable, accrued cost of gas and liquids,
related party payables and deferred revenues
(89)
                     
(57)
          
4
                 
(22)
                    
(20)
                     
18
           
34
               
Distributions of earnings received from unconsolidated
affiliates
(37)
                     
(35)
          
(36)
              
(29)
                    
(29)
                     
(34)
          
(29)
              
Other assets and liabilities
2
                        
(135)
        
1
                 
1
                       
-
                         
-
              
-
                 
Net (Loss) Income
42
$                    
11
$         
(5)
$            
(9)
$                    
(1)
$                     
29
$         
29
$           
Add:
Interest expense, net
41
                      
41
           
37
               
36
                     
29
                      
28
           
30
               
Depreciation and amortization
74
                      
68
           
48
               
59
                     
46
                      
45
           
51
               
Income tax expense (benefit)
2
                        
-
              
(2)
               
1
                       
-
                         
-
              
-
                 
EBITDA
159
$                  
120
$       
78
$           
87
$                   
74
$                    
102
$       
110
$         
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted
EBITDA
66
                      
60
           
63
               
57
                     
54
                      
59
           
57
               
Income from unconsolidated affiliates
(37)
                     
(31)
          
(35)
              
(27)
                    
(21)
                     
(34)
          
(32)
              
Non-cash loss (gain) from commodity and embedded
derivatives
(14)
                     
(4)
             
18
               
(2)
                      
7
                        
(22)
          
(2)
               
Other income, net
(2)
                       
10
           
3
                 
2
                       
1
                        
10
           
1
                 
Adjusted EBITDA
172
$                  
155
$       
127
$         
117
$                 
115
$                  
115
$       
134
$         
Add (deduct):
Interest expense, excluding capitalized interest
(40)
                     
(46)
          
(42)
              
(41)
                    
(34)
                     
(41)
          
(35)
              
Maintenance capital expenditures
(9)
                       
(13)
          
(7)
               
(8)
                      
(11)
                     
(7)
             
(7)
               
SUGS Contribution Agreement adjustment *
-
                     
9
              
14
               
-
                    
-
                     
-
          
-
              
Proceeds from asset sales
-
                     
5
              
12
               
4
                       
2
                        
7
              
13
               
Other adjustments
(8)
                       
(9)
             
(3)
               
(4)
                      
(3)
                       
(3)
             
(2)
               
Distributable cash flow
115
$                  
101
$       
101
$         
68
$                   
69
$                    
71
$         
103
$         
* Includes an adjustment to CAFD related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
Three Months Ended
($ in millions)
1   Historical results have been retrospectively adjusted to combine Regency’s results with SUGS results due to the as-if pooling accounting treatment required for an acquisition between commonly controlled entities