Regency Energy Partners LP - FORM 8-K - EX-99.1 - November 17, 2014

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Regency Energy Partners LP
2014 Investor Day
November 17, 2014
Exhibit 99.1

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,” “will,” “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 including
the following risks: unexpected difficulties in integrating Regency’s operations as a result of any significant acquisitions, including Regency's acquisition
of Eagle Rock Energy Partners, LP’s midstream business. Additional risks include, volatility in the price of oil, natural gas, condensate, and natural gas
liquids and coal; 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 or enforcement practices 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 use and development of renewable energy or limit use or development of fossil
fuels and the midstream sector of the natural gas industry, the oil industry and coal mining industry, including those that relate to climate change and
environmental protection and safety, including with respect to emissions levels applicable to coal-burning power generators and permissible levels of
mining runoff, weather and other natural phenomena, industry changes including the impact of consolidations and changes in competition, the
regulation of transportation rates on our natural gas, NGL, and oil pipelines, the Partnership’s ability to obtain indemnification related to clean up any
hazardous materials release on satisfactory , 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. The extent to which the amount and quality of actual production of our coal differs from estimated recoverable
coal reserves, the experience and financial condition of our coal  lessees, including our lesses’ ability  to satisfy their royalty , environmental,
reclamation and other obligations to us and others, operating risks, including unanticipated geological problems, incidental to our Gathering and
Processing segment and Natural Resources segment, the ability of our lesses to produce sufficient quantities of coal on an economic basis from our
reserves and obtain favorable contracts for such production, delays in anticipated start-up dates of new development in our Gathering and Processing
segment and our lessees’ mining operation and related coal infrastructure projects, including the timing of receipt  of necessary governmental permits
by us or our lessees; and uncertainties relating to the effects of regulatory guidance on permitting under the Clean Water Act and the outcome of
current and future litigation regarding mine permitting. 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.

Agenda
3
1. Overview & Strategy
Mike Bradley, President & CEO
2. Natural Gas Transportation and                            
Gathering & Processing Overviews
Jim Holotik, EVP & Chief Commercial Officer
3. Integration & Synergies Update
Jennifer Street, Vice President of Engineering
4. NGL Services Overview
Steve Spaulding, EVP of Lone Star NGL
5. Contract Services Overview
Chad Lenamon, President of Contract Services
6. Financial Review
Tom Long, EVP & CFO
7. Conclusion
Mike Bradley, President & CEO
8. Q&A

Overview & Strategy

Major Transformation Since Last Investor Day
5
Extensive
midstream
portfolio
and
strong
position
in
majority
of
high-growth
shale
plays
driving
expansion opportunities
•
Completed approximately $9 billion in strategic acquisitions
•
Combined synergies in excess of $85 million
•
Completed $1.5 billion in organic growth projects, primarily from the legacy Regency assets
•
Transformed into one of the largest and most diverse G&P MLPs
•
Achieved significant G&P scale in 5 prolific producing regions
•
Increased
organic
growth
opportunities
driven
by
strong
position
and
scale
•
Current backlog is approximately $2.6 billion, which provides visibility into future earnings
growth
•
High percentage of fee-based margins
•
Diversity of business mix, scale and strategic location of assets enhances stability of
cash flows
•
Quarterly distributions have increased 8% since Q2 2013
•
Well positioned for continued distribution growth as recently completed and new
projects
under
construction
ramp
up
from
2015
–
2017
Growth
Scale &
Diversity
Backlog
Stability of
Cash Flows
Distributions

6
Highlights Since 2013 Investor Day
1. Includes FY 2013 and 9 months ended 2014 capex
Acquisitions -
$9 Billion
SUGS
PVR Partners
Hoover Energy
Midstream
EROC Energy
Midstream
Organic Growth -
$1.5 Billion¹
•
Eagle Ford Expansion
•
Dubach Processing Expansion
•
Dubberly Gathering Expansion
•
Contract Services Growth
•
Frac II
•
Tilden and ELG Treating Expansions
•
Red Bluff Processing Expansion
Adjusted EBITDA & DCF
Throughput & NGL Production
$155
$344
$101
$215
$0
$50
$100
$150
$200
$250
$300
$0
$100
$200
$300
$400
$500
Q2 2013
Q3 2014
Q2 2013
Q3 2014
Adjusted EBITDA
DCF
2.2
5.7
97
178
0
50
100
150
200
250
300
0
1
2
3
4
5
6
7
8
Q2 2013
Q3 2014
Q2 2013
Q3 2014
Throughput
NGL Production

7
Substantially Increased Footprint
Transformed into a larger, more diverse G&P midstream provider with strong positions in 5 strategic basins
Contract Services segment has expanded its existing positions and has added 4 new shale plays to its footprint
Ark-La-Tex
•
EROC acquisition significantly
increased footprint in East
Texas, where drilling activity is
expected to increase, driving
expansion opportunities
•
Expanding legacy assets to
meet increased demand from
Cotton Valley drilling
Marcellus/Utica
•
PVR assets provide significant
position in core area of Appalachian
Shales, which are presenting
substantial growth opportunities
Midcontinent/Granite Wash
•
Acquisitions have created
stronger position, driving
significant synergy opportunities
and improved system efficiencies
Permian
•
A prominent position in most
active counties in Permian driving
processing, crude oil and water
gathering opportunities
South Texas
•
Positioned in the oil and liquids-
rich Eagle Ford, which is driving
increased treating opportunities
and possible further expansion of
the Eagle Ford Gathering System

Permian G&P
NGL Services
Natural Resources
8
Margin By Business
Significant Portfolio Growth & Diversification
FY 2012
FY 2015E
Acquisitions and organic growth are driving a more balanced and diversified portfolio
NLa G&P
Eastern G&P
Natural Gas Transportation
Mid-Continent G&P
South Texas G&P
Contract Services
8%
6%
5%
17%
11%
25%
14%
8%
3%
17%
7%
15%
12%
13%
10%
28%

9
Gathering & Processing Margin By Region
Significant Scale in 5 Prolific Producing Regions
FY 2012
FY 2015E
26%
11%
24%
18%
21%
23%
17%
13%
47%
Mid-Continent G&P
NLa G&P
Permian G&P
South Texas G&P
Eastern Region
PVR,
EROC
and
Hoover
acquisitions
provided
significant
scale
and
geographic
diversification
to
gathering and processing segment, and further diversified margins

SUGS Growth Projects
RGP Other Growth Projects
NGL Logistics Growth Projects
Contract Services Growth Projects
10
Scale & Position Driving Increased Organic Growth
Acquisition Growth Drivers
Organic Growth Backlog
Other Growth Drivers
PVR Growth Drivers
•
Utica Ohio River Gathering JV
•
Lycoming Expansion
•
East Clinton Expansion
•
Mi Vida Processing Plant
•
Permian Processing Expansion III
•
Frac III
•
Mariner South Pipeline
•
Lone Star Express Pipeline
•
Dubberly Cryo and NGL Pipeline
•
Eagle Ford Expansion
•
Permian oil gathering system
expansion
•
STX Treating Expansions
•
Revenue generating horsepower
$2,600
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Contract
Services
Other G&P
NGL Logistics
SUGS
PVR
Total Backlog
Approximately 90% of project backlog is fee based

Visibility for Future Earnings & Distribution Growth
11
Mi Vida Processing Plant
2015
2016
2017
Dubberly Liquids Express Pipeline
Dubberly Cryo Processing Expansion
Eagle Ford Expansion
Utica Ohio River Gathering JV
Lycoming Expansion
Permian Processing Expansion III
Mariner South
Fractionator III
Major Announced Growth Projects
Lone Star Express Pipeline

Assets Strategically Located
Source: Company data and Credit Suisse Energy Research. Futures strip as of 11/10/2014
Year:
2014
2015
2016
2017
2018
2019
2020
2021+
WTI Oil:
$93.85
$80.17
$80.04
$79.93
$79.91
$80.12
$80.12
$80.12
NYMEX Gas:
$3.89
$3.62
$3.85
$4.03
$4.18
$4.32
$4.32
$4.32
IRR by Basin
12
No Footprint
RGP G&P Footprint

2015 Objectives
13
Execution
Invest In Growth
Leverage Integrated
Midstream Platform
Maintain Stable
Cash Flows
•
Offer fully integrated
midstream services to
customers
•
Leverage expertise between
business segments
•
Package services utilizing all
business segments and
creating new growth
opportunities
•
Utilize integrated platform
of assets to capture
additional, creative
investment opportunities
•
Strategic acquisition
opportunities to expand
portfolio and diversify into
new plays
•
Focus on growing DCF/unit
•
Continue executing on
integration of PVR and EROC
assets
•
Achieve a minimum of $85
million in synergies
•
Successfully execute on
organic growth project
backlog of  $2.6 billion
•
Maintain high percentage of
fee-based cash flows
•
Strategically target growth
opportunities backed by
fee-based commitments
•
Mitigate a substantial
portion of commodity risk
with a strategic hedging
program

Transportation and Gathering & Processing

1 All information as of September 30, 2014
15
Transportation and Gathering & Processing: Asset Overview
Gathering & Processing Asset
Summary¹
April 2013
September 2014
% 
Growth
Total Processing Capacity (MMcf/d)
930
2,700
190%
Total Gas Treating Capacity (MMcf/d)
1,320
1,965
49%
Transportation Asset Summary¹
Total Intrastate Transportation
Capacity
2.1 Bcf/d
Total Interstate Transportation
Capacity
1.8 Bcf/d
Gathering & Processing Throughput
2,178  
2,178  
2,216  
2,392  
4,886
5,680
1,000
2,000
3,000
4,000
5,000
6,000
7,000
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Mid-Con
South Texas
Ark-La-Tex
Permian
Eastern
-

•
PVR provides a significant position in Appalachian Shales with extensive growth opportunities
•
Exceeded
2
Bcf/d
of
gathering
volumes
through
expansions
of
well
connects
•
Establishing
strong
position
in
Utica
with
2.1
Bcf/d
of
firm
commitments
on
the
36”
greenfield
Ohio River system pipeline
Accomplishments Since Investor Day 2013
16
Permian
South Texas
Mid-Continent
Eastern
Ark-La-Tex
•
Increased total treating capacity from 170 MMcf/d to 350 MMcf/d
•
Added 17,000 Bbls/d of oil stabilization capacity with 40,000 Bbls/d of pipeline capacity
•
Finalizing build out of 600 MMcf/d Eagle Ford Expansion Project
•
Acquired Hoover midstream assets, expanding gas, oil and water gathering capabilities
•
Increased cryogenic processing by 200 MMcf/d with new Red Bluff plant
•
Completed integration of SUGS assets and grew system volumes by 50%
•
PVR
and
EROC
acquisitions
increased
processing
capacity
from
50
MMcf/d
to
890
MMcf/d
•
Executing
>$15M
of
operational
synergies
with
the
integration
of
Midcon
assets
•
Connected over 200 wells year to date
•
Increased
processing
capacity
at
Dubach
facility
from
140
MMcf/d
to
210
MMcf/d
•
Completed construction of up to 400 MMcf/d additional gathering capacity in January 2014
•
Completed upgrades to north Louisiana complex to accommodate an additional 220 MMcf/d
Total G&P throughput increased by 161% and NGL production by 100% since Q2 2013

Intrastate Transportation: RIGS
17
RIGS Details
Capacity Pipeline
Length
2.1 Bcf/d
450 miles
Major Shippers
Petrohawk
Exco
BG
El Paso Corporation
Chesapeake
Louisiana Markets
Served
Union Power
Swepco
Louisiana Tech
Major Pipeline
Interconnections
Texas Gas
Tennessee
Trunkline
Southern Natural
ANR
Columbia Gulf
Tetco
Firm Transportation
Commitments
Expansion volumes fully
subscribed with ~85% demand
charges with ~6 years remaining
on contracts
~99% demand charges on Legacy
system with ~ 1-3 years
remaining
RIGS Haynesville Joint Venture Partnership Structure¹
50/50 Joint Venture with Alinda Capital Partners
Regency operates the assets on behalf of the Joint Venture
Interruptible volumes on RIGS associated with new Cotton Valley drilling around Terryville gathering system have
risen over the course of the year
1 Regency owns 49.99% of the Haynesville Joint Venture, GE Energy Financial Services owns 0.01%
Legend
RGP Plant Facility
RIGS Pipeline

Interstate Transportation: MEP
18
MEP Details
Capacity /
Pipeline Length
1.8 Bcf/d
500 miles
Major Shippers
Chesapeake
Cross Timbers
EOG Resources
Newfield Exploration
Major Pipeline
Interconnections
Texas Gas
NGPL
ANR
Columbia Gulf
Southern Natural
CEGT
TETCO
Destin
Transco
Firm Transportation
Commitments
Primarily fee-based revenues
supported by long-term demand
agreements
Approximately 5 years remaining on
contracts
MEP Joint Venture Partnership Structure
50/50 Joint Venture with Kinder Morgan
Kinder Morgan operates the assets on behalf of the Joint Venture

Gathering and Processing: South Texas
Capacity
2014
Total Treating Capacity (MMcf/d)
350
Total Condensate Gathering Capacity
(Bbls/d)
37,000
19
Engineering expansion of the Eagle Ford Gathering System as producers increase production and utilize longer laterals and      
new frac techniques
Phase
III
expansion
of
Edwards
Lime
JV
underway
with
new
100
gpm
treater and 17,000 Bbls/d stabilization capacity
Constructing
a
new
500
GPM
treater
at
Tilden
with
incremental
70
MMcf/d of treating capacity, expected in service Q2 2015
Growth Opportunities
South Texas Asset Map
Total South Texas gathering throughput increased 14% since Q2 2013
Accomplishments
Added 17,000 BPD of oil stabilization capacity with
approximately 40,000 BPD of takeaway capacity
Increased total treating capacity from 170 MMcf/d
to 350 MMcf/d at Tilden and Edwards Lime JV
plants
Nearing completion of total build out of 600
MMcf/d Eagle Ford gathering system
Increased Eagle Ford gathering system volumes by
15% and crude oil volumes by 14% since Q2 2013

Gathering and Processing: Ark-La-Tex
Capacity
2014
Total Processing Capacity (MMcf/d)
758
Total Treating Capacity (MMcf/d)
325
Constructing new 200 MMcf/d cryogenic processing facility at Dubberly, expected in service in Q2 2015
Constructing new 47 mile, 10-inch Dubberly NGL pipeline, to provide ~40,000 Bbls/d of NGL takeaway
Increase condensate gathering and stabilization capacity
Accomplishments
Ark-La-Tex Asset Map
Expanded Dubach cryogenic plant capacity to 210
MMcf/d in Q2 2013
Constructed 32 miles of 24-inch pipeline capable of
gathering up to 400 MMcf/d to north Louisiana complex
Completed 100 MMcf/d Dubberly refridge plant upgrade
Completed three processing projects and interconnects
to accommodate 120 MMcf/d of incremental volume
EROC system in position to gather Eaglebine and
Tuscaloosa Marine Shale volumes
Growth Opportunities
Increased Ark-La-Tex throughput volumes by 50% and NGL production by 74% since Q2
2013
20

Gathering and Processing: Permian
21
Permian Asset Map
Increased gathering throughput by 50% and NGL production by 38% since Q2 2013
Capacity
2014
Total Processing Capacity (MMcf/d)
940
Total Treating Capacity (MMcf/d)
890
Constructing 200 MMcf/d Mi Vida cryogenic processing facility, expected online in Q2 2015, with a second 200 MMcf/d
cryogenic processing facility expected online in Q3 2015
Constructing incremental 110 MMcf/d treating capacity at Halley to increase gathering system reliability
Continuing expansion of oil gathering system, partnering with SXL for takeaway options on their new Delaware Basin Extension
Constructing >10,000 Bbls/d of condensate stabilization in region to capture liquids upgrade
Engineering a third 200 MMcf/d processing plant in key Permian producing area
Growth Opportunities
Accomplishments
Successfully integrated SUGS and Hoover acquisitions
Increased total processing capacity from 250 MMcf/d
to 940 MMcf/d
Start-up of 200 MMcf/d Red Bluff cryogenic
processing facility in Q3 2013
Expansion of oil gathering from 25,000 Bbls/d to
100,000 Bbls/d expected online December 2014
Added over 400 miles of oil, gas and water pipelines

22
Gathering and Processing: Eastern Region
Total Eastern region volumes grew 36% to 1.9 million MMbtu/d since Q2 2013
Accomplishments
Auburn/Korbin
Compressor
Station
adding
horsepower
to
increase
TGP
deliverability
by
200
MMcf/d,
expected
online
in
Q1
2015
Lycoming
System
Expansion
trunkline,
gathering
and
compression
will
expand
system
by
500
MMcf/d
,
expected
online
in
2015/2016
East Clinton Gathering Expansion trunkline, gathering and compression will expand delivery into Transco by 300 MMcf/d,
expected online in 2015/2016
Expanded Utica Project to over 2 Bcd/d of demand capacity
Capacity
2014
Total Interconnect Capacity (Bcf/d)
~2.2
East Texas Asset Map
Growth Opportunities
Expanded delivery into downstream transportation
markets by 730 MMcf/d
Exceeded 2 Bcf/d of actual gathered volume
Signed Utica Ohio River Valley Joint Venture
agreement, which included acreage dedication and
over 2 Bcf/d of firm commitments from shippers
Exercised option to construct Cadiz lateral

Utica Ohio River Project
Commercial Highlights
•
Joint Venture between Regency and AE-MidCo
•
Over 2 Bcf/d of firm volume commitments
•
Provides interconnects with REX, TET, and
potentially others
•
Project cost at ~$500 million; Regency
contributing 75% and AE-MidCo 25%
Project Overview
•
52-mile, 36-inch trunkline  with minimum 2.1
Bcf/d capacity, a northern tie-in would increase
capacity to 3.5 Bcf/d
•
Trunkline Phase I expected in service Q2 2015 and
Phase II expected in service 3Q15
•
1.125 Bcf/d booster station to REX, in service
3Q15
•
12 mile, 36-inch lateral initially connecting to the
tailgate of Cadiz processing plant  and Harrison
County wellhead production
Utica Ohio River Joint Venture
Utica Ohio River Joint Venture creates a first-mover advantage, and will be a key take-away option for
Utica lean-gas
23

Gathering and Processing: Mid-Continent
Capacity
2014
Total Processing Capacity  (MMcf/d)
900
Total Treating Capacity (MMcf/d)
400
24
Completed acquisitions of PVR and EROC’s midstream
businesses, positioned Regency as a major player in
region
Increased total processing capacity from 50 MMcf/d to
890 MMcf/d
Executing on >$15M in operating synergies with asset
integration plan
Connected over 200 wells on combined system year to
date
Rig count for area remains ~100 for stacked
production formations
Accomplishments
Mid-Continent Asset Map
Growth Opportunities
Capturing commercial opportunities with combined RGP, PVR and EROC systems through larger footprint and asset integration
Securing oil and water gathering opportunities in the Woodford, Cleveland, Marmaton, Mississippi Lime and Granite Wash
Reactivating
EROC
transloader
and
rail
service
to
provide
access
to
stronger
liquids
markets
Increased Mid-Continent throughput volumes over  400% since Q2 2013 with PVR and EROC acquisitions

Gathering & Processing Opportunities Summary
25
Bone Spring/Permian
•
Additional 400 MMcf/d cryogenic
processing capacity coming online
in 2015. New capacity will utilize
NGL takeaway through Lone Star’s
NGL pipelines and fractionation
•
Expanding oil gathering system,
and utilize relationship with SXL for
takeaway options on their
announced Delaware Basin
Extension project
Ark-La-Tex
•
200 MMcf/d cryogenic processing
capacity coming online in Q2 2015
•
Complete 47 mile, 10% NGL Express line
•
Expand Dubach stabilization capacity by
4,000 Bbls/d
Eagle Ford Shale
•
Install 500 gpm of treating at Tilden to increase
treating capacity to 210 MMcf/d
•
Phase III Edwards Lime JV new 100 gpm treater,
providing incremental 25 MMcf/d capacity
Mid-Continent
•
Creating super system to increase
flexibility and capture new gas, oil
and water opportunities
•
Constructing storage and
reactivating transloader
Eastern
•
Completion of Lycoming Expansion adding
500 MMcf/d of throughput to Transco
•
Phase I of the Utica Ohio River project is
expected to be in service in Q2 2015 and
phase II to come online in 3Q15
Total Gathering and Processing volumes are expected to grow 18% year-over-year

Integration & Synergies
Update

Combined EROC and PVR Synergies Overview
27
Total Combined PVR and EROC Synergy Savings on an Annual Basis: $85M+ with Upside Potential
G&A Savings
Operating
Expense Savings
Gross Margin
Increase
Bond Refinance
Savings
Capital
Reduction &
Deferment
•
~15% in headcount consolidation
•
Elimination of corporate overhead costs
•
Benefits, insurance and office consolidation
•
IT systems and software consolidation
•
Lower OPEX with Midcon asset consolidation
•
Streamlined, flattened Midcon operations organization
•
Capture additional revenue with combined Midcon system flexibility
•
Increase system efficiencies through system optimization
•
Lower interest rates with PVR and EROC bonds refinance
•
Lower maintenance capital with new maintenance practices
•
Reduced capital from use of underutilized assets
2015
2016
2014
$0
$85
Year-Over-Year
Synergies Execution
Timeline
Upside
Potential

Midcon Asset Synergies Overview
28
Operating Expense Reduction
Maintenance & Growth Capital Reduction
Improve System Reliability
Increase Plant and Compression Efficiencies
Improved Processes
System Flexibility
Asset Consolidation
PVR, EROC & Regency Midcon System: Pre Close 
Combined Midcon System: Post Close 
Midcon Synergies Benefits
Midcon Synergies Strategy
Plant and compression consolidation
Two HP system & small interconnect pipelines
New maintenance and procurement practices
Streamline operations organization

NGL Services

30
NGL Services: Highlights
Announced Projects
Lone Star Express NGL Pipeline
Conversion
of
existing
12”
NGL
line
to
crude
oil
service
Fractionator III
Mariner South expected in-service by year end
Volume Growth
Volumes transported are up over 25% year
over year
Fractionated volumes are up over 129% year
over year
Future Opportunities
Footprint for Fractionators IV, V & VI
Expansion of NGL export capacity
Continued development of Houston ship
channel NGL distribution system
Development of 8 additional NGL storage
caverns

31
NGL Services: Assets
•
~53 Million barrels NGL storage
•
Permitted to drill additional 8 caverns
•
2,000+ miles of NGL Pipelines
•
~ 400 Mbpd of raw make transport 
capacity 
•
Expanding capacity to 700 Mbpd
•
210 Mbpd LPG export terminal
•
80 Mbpd of Diluent export capacity
•
Extensive Houston Ship Channel
pipeline network
•
Two 100,000 Bpd fractionator at Mont
Belvieu
•
Third Fractionator (Dec 2015)
•
Ability to build a total of 6 Mont Belvieu
fractionators on current footprint 
•
Two cryogenic processing plants
•
25,000 Bpd fractionator at
Geismar, LA
•
Raw make truck rack
Godley
Baden
LaGrange/Chisholm
Mt Belvieu
Kenedy
Jackson
Sea Robin
Geismar
Sorrento
Chalmette
Hattiesburg
ETP Justice
Storage
Fractionation
Lone Star West Texas Gateway Expansion
ETP Spirit
ETP Freedom
Plant
Existing Lone Star
Approved Lone Star Express
ETP-Copano Liberty JV
Refinery Services
NGL Storage
Pipeline Transportation
Fractionation and Processing

32
NGL Services: Integrated Assets Allow For Synergies Across
Family
ETP Justice NGL Line
ETP Freedom NGL
Lone Star West Texas Gateway
Lone Star West Texas NGL
ETP-Copano JV Liberty NGL
ETP Spirit NGL
Other Fractionators
Lone Star Fractionators
Connected Plants
Regency Plants
ETP Plants
ETP
Godley 1, 2, 3, 5
Lone Star
West Texas Pipeline 12”
(140 Mbpd)
ETP
Freedom/Liberty
(75 Mbpd)
ETP
Justice 20”
(340 Mbpd)
Lone Star
Mt. Belvieu Frac
(200 Mbpd)
NGL Storage Capacity (50
MMbbl)
ETP
Kenedy
ETP
Jackson 1, 2, 3, 4
ETP
LaGrange/Chisholm
Lone Star
West Texas Gateway 16”
(210 Mbpd)
RGP
Jal
RGP
Haley
RGP
Coyanosa
RGP
Tippett
RGP
Waha
RGP
Bone Spring
RGP
Mivida
RGP
Red Bluff
RGP
Keystone
Mariner South
Batching C2 & C4
Capacity
(200 Mbpd)
ETP Rebel

33
NGL Services: Performance
1
Represents 100% of Lone Star adjusted EBITDA
2013
Adjusted
EBITDA
by
Segment
2014
Estimated
Adjusted
EBITDA
by
Segment
1
1
NGL Storage
NGL Pipeline Transportation
Refinery Services
Fractionation
Other

34
NGL Services: Lone Star Express Pipeline
533 miles of new 24”
and 30”
NGL
pipelines from the Permian Basin to
Mont Belvieu
Capacity
•
Initial scope of 375 MBPD
•
Expandable up to 495 MBPD
Contracted volumes in excess of 200
MBPD
Conversion of LST’s  West Texas NGL
line to crude oil service
Expected In-Service
•
Phase I –
24”
Q1 2016
•
Phase II –
30”
Q3 2016
•
Phase III –
Crude Oil Conversion Q1
2017
Estimated cost -
$1.5 to $1.8 billion

35
NGL Services: Lone Star’s Mont Belvieu Complex
Frac I 100 Mbpd
Dec ‘12
Frac II 100 Mbpd
Oct ‘13
Frac IV , V , IV
Frac III 100 Mbpd Dec
‘15
De-C2 100 Mbpd
Nov ‘14

36
NGL Services: Mariner South

Contract Services

Contract Services: Asset Offerings
38
CDM Resource
Management
Zephyr Gas
Services
Merged Into
CDM
Resource
Management
Contract
Compression
•
Gas compression packages ranging
from 75 HP to 3,550 HP
Amine
Treating
Fuel Gas
Conditioning
Condensate
Stabilization
•
Separate and stabilize condensate
project for sale or transportation
Gas Cooling
•
Liquids extraction
•
Cool gas to spec
Turnkey
Construction
& Installation
•
Design, engineer and construct
standard or custom facilities
•
Provide all equipment  and contract
services
•
Removal
of
CO
2
and/or
H
2
S
•
5 GPM to 400 GPM
•
Reduce high BTU for natural gas
engine fuel in rich gas areas

Contract Compression: Asset Overview
Growth since April 2013
Horsepower Growth
Footprint as of April 2013
39
CDM is well positioned to provide fee-based, turn-key services in the majority of all shale plays and
equipped to capitalize on those that are currently experiencing increased drilling activity 
Revenue generating HP is currently at an all-time high;
seen net horsepower growth in all five regions
Expanded into Mississippi Lime in 2014, and continued
to grow footprint in three newest plays (Niobrara,
Utica, Avalon)
Current fleet utilization is approximately 96%
Opportunities for turnkey installations continue to
increase and have become a good source of margin
diversification
Recent Developments
Geographic Diversification
853
897
973
1,005
1,072
1,140
1,216
-
200
400
600
800
1,000
1,200
Q1 2013
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Revenue Generating Horsepower
Permian/Avalon/
Bone Spring/Wolfcamp/
Wolfberry/Cline
Niobrara
Granite Wash /
Mississippi Lime
Marcellus/
Utica

40
Horsepower By Shale Play
Target Shale Plays for Expansion
2015 Opportunities and Growth Strategy
Contract Services: 2015 Outlook
Larger gas-lift and turn-key facility installation opportunities
expected to drive growth in Eagle Ford and Permian
Expect additional growth in Niobrara Shale as customers
finalize expansion plans
Increasing customer demand driving new Gulf Coast
opportunities
Approximately 100,000 HP is booked and scheduled to be
set the remainder of 2014 and projected to reach 1.3 million
HP by year-end 2014
2015 focus will be on filling in gaps within specific
customers’
established operating regions
Significant increase in demand for compression in shale plays, which is expected to continue throughout 2015

Production Services: Asset Overview
Treating business is well positioned in several rapidly growing shale plays, which is expected to allow
CDM to capitalize on increased activity and production
41
Growth since April 2013
Footprint as of April 2013
Marcellus/
Utica
Niobrara
Granite Wash /
Mississippi Lime
Barnett
Permian/Avalon/
Bone Spring/Wolfcamp/
Wolfberry/Cline
Fayetteville
Gulf Coast
Eagle Ford Shale
10%
20%
30%
40%
50%
60%
70%
80%
90%
50
100
150
200
250
300
350
400
2012 YE
2013 YE
2014 FYE
Revenue Generating Assets
Idle
Utilization %
Asset Utilization
71
311
242
59
95
191
0
0%
Recent Developments
Smaller Refrigeration Plants
Continued focus on full, turn-key installations
Liquids-rich shale plays continue to drive improved
asset utilization (current utilization is 82%)
Diversified product mix to match market demand
Smaller Amine Plants
H2S removal equipment
Successful design and engineering of liquids-rich
products
Fuel Gas Conditioning Skid
Cotton Valley

42
Assets by Shale Play
Bookings of 720 GPM in 2014 year-to-date 
Targeting new turn-key projects in Eagle Ford & Permian
Basin shale plays for 2015
Further diversify customer base and product mix in
Mississippi Lime and Permian Basin shale plays
Segregated sales focus on Production Services opportunities
3
rd
Party Operations & Maintenance
2015 Opportunities and Growth Strategies
Revenue by Asset
2013 YE
2015 FYE
28%
61%
11%
52%
37%
11%
38%
40%
2%
11%
9%
2%
Diversified Equipment
Amine
Gas Coolers
Haynesville
Eagle Ford
Fayetteville
Tuscaloosa Marine / Eaglebine
Permian Basin / Bone Spring
Barnett / Granite Wash
Niobrara
Marcellus/Utica
20%
41%
4%
4%
17%
1%
6%
8%
2015 FYE
2013 YE
Production Services: 2015 Outlook
In 2014, have experienced an increase in sales coverage and diversified customer base as a result of  the successful
integration of the treating and compression sales teams

43
Contract Services: Where We Are Going
In summary, the contract services segment presents tremendous opportunities and upside potential driven by
demand from existing and developing shale plays
Opportunities Summary
Basins
Continue to focus on liquids-rich basins: Eagle Ford, Permian and Woodbine
Execute in newer shale plays: Niobrara, Utica, and Mississippi Lime
Dry-gas basin activity remains stable in the Haynesville Shale
Focus
Continue to focus on cross-selling ability
–
Leverage
both
companies’
traditional
customer
base
–
Move gas from the wellhead to the pipeline via compression, treating and production services
–
Increased ability to focus on developing new customers
Fill in geographical voids by targeting specific customers and/or opportunities
Organization Structure
–
Continue to maintain segregated operations organization
Fleet/Product Mix
Compression: Staged and sized appropriately
Fuel Skids: Condition rich fuel gas commonly found in majority of shale plays
Amine
Plants:
H
2
S
and
CO
2
common
in
numerous
shale
plays
and
focus
on
smaller
opportunities
Gas Coolers: Enhances economics of wellhead gas stream and adding additional assets to fleet
Other
fleet
additions
to
meet
market
demand:
H
2
S
Removal
and
Refrigeration
Plants
With these synergies, and the appropriate product mix, CDM is well positioned for growth and poised to
capture future opportunities as they arise

Financial
Review
Review

Financial Objectives
45
Distribution Growth
Q3 2014 marked Regency’s sixth consecutive increase in quarterly distributions,
representing 9% distribution growth over the period
Distribution Coverage
LTM distribution coverage through Q3 2014 was 1.00x
Goal is to maintain coverage between 1.0x and 1.1x
Credit Ratings and
Leverage
Debt/
Pro
Forma
EBITDA
was
4.74x
as
of
September
30,
2014
1
Leverage target is 4.0x to 4.25x
Interest Rate
Management
Indebtedness
is
substantially
fixed
rate,
with
approximately
10%
floating
today
Comfortable with up to 20-25% floating rate debt
Strong Balance Sheet
Upsizing of credit facility to add additional liquidity
Issued/acquired
roughly
$3.9
billion
of
debt
and
$5.0
billion
of
equity
this
year
Risk Management
Strong mix of fee-based cash flow (75% for 2015)
Target entering 2015 with approximately two-thirds of exposure hedged
1
Based on compliance calculations
Achieve Investment Grade Metrics

Distributions
46
Since Q2 2013, RGP has delivered 6 consecutive distribution increases, including the $0.0125/unit
increase in Q3 2014, which represents $2.01 per unit on an annual basis
$0.465
$0.47
$0.475
$0.48
$0.49
$0.5025
$0.44
$0.46
$0.48
$0.50
Q2 2013
Q3 2013
Q4 2013
Q1 2014
Q2 2014
Q3 2014
Distribution ($/LP unit)

Capital Markets Update
47
Revolving Credit Facility
•
Launched amendment early this month
•
Increased size by $500 million up to $2 billion
•
Improved pricing and terms
•
Extended maturity to 5 years
•
Expected to close on November 21, 2014
•
Provides an efficient source of liquidity for growth capital funding
•
Completed approximately 65% of the program to date
Called Senior Notes
•
Called
$600
million
of
6.875%
outstanding
notes
(redemption
December
2
nd
)
$400 million ATM Program
Additional
near
term
debt
and/or
equity
offerings
will
be
driven
by
organic
growth
spend,
opportunistic M&A
transactions, and liability management opportunities

Debt complex is well-balanced, with no maturities in the next 3 years
Weighted average interest rate will be 5.74% after 6.875% notes are redeemed next month
Debt Maturity Profile
48
6.875
5.75
6.50
5.875
5.50
2.53
5.00
4.50
8.375
6.50
8.375
-
500
1,000
1,500
2,000
2,500
Called
Nov ‘14
Callable
June ‘15
RGP Notes/Revolver
Undrawn Revolver
PVR Notes
EROC Notes

Organic Growth Project Backlog
49
Major Projects
($ in Millions)
2015 Growth Capital
Total Backlog
Gathering & Processing
Mi
Vida
Processing
Facility
1
Dubberly Liquid Express Pipeline
Dubberly Processing Expansion
Eagle Ford Expansion
Ohio
River
Gathering
Joint
Venture
1
Lycoming Expansion
Permian Processing Facility
Other
$800
$1,600
Contract Services
$300
$400
NGL Services
1
Mariner South
Fractionator III
Lone Star Express Pipeline
Other
$390
$630
Total Growth Capital
$1,490
$2,630
1
Represents Regency’s proportionate JV interest
Major growth projects expected to support distribution growth as projects come online

Diverse Portfolio
50
In the past 3 years, Regency has grown EBITDA by over 300%, driven by strategic acquisitions and accretive
organic growth projects
Recent acquisitions have significantly increased Regency’s gathering and processing activity
FY 2012
Estimated 2015
1
Excludes segment EBITDA from the Corporate and Others Segment
Adjusted EBITDA
1
Gathering & Processing
Transportation
Natural
Resources
Contract Services
NGL Services
32%
34%
21%
12%
63%
10%
3%
13%
11%

Strong Fee-based Cash Flows
51
FY 2014 Estimated
FY 2013
FY 2015 Target
FY 2012
Fee-based
Hedged Commodity
Un-hedged Commodity
Currently, over one-third of 2015 commodity exposure is hedged
Adjusted Total Segment Margin
83%
8%
9%
76%
15%
9%
72%
17%
11%
75%
15%
10%
Target having two-thirds of commodity hedged for 2015

DCF Sensitivities
52
A $5.00/bbl movement in crude prices would result in a $7M change to Regency’s forecasted DCF for 2015
A $0.25/MMbtu movement in natural gas would result in an $7M change to Regency’s forecasted DCF for 2015
A $0.05/gallon move in NGL prices would result in a $5 million change to Regency’s forecasted DCF for 2015
Regency is currently hedged 49% on natural gas/ethane, 37% on natural gasoline/condensate and 29% on
propane and butane
Commodity
$/Move
$ Impact
Natural Gas
+/-
$0.25/MMbtu
+/-
$7M
NGLs
+/-
$0.05/gallon
+/-
$5M
Condensate
+/-
$5/barrel
+/-
$7M
DCF Sensitivity to Commodity Price Changes – Full Year 2015

Conclusion

Conclusion
54
•
Completed more than $10.5 billion in organic growth and acquisitions in the last two years
•
Project backlog of approximately $2.6 billion expected to increase
•
Assets strategically located in majority of the most prolific shale plays and basins
•
Strong position in key producing plays driving significant organic growth program
•
Comprehensive midstream service provider with significant presence across the midstream value chain
•
Oil and water gathering opportunities will expand overall service offerings
•
High percentage of fee-based margins increasing with organic backlog
•
Diversity of business mix, scale and strategic  location of assets enhances stability of cash
flows
•
Scale and backlog provide visibility for continued distribution growth
Strong
Visibility for 
Growth
High-Quality
Assets
Integrated
Midstream
Platform
Stability &
Diversity of
Cash Flows
Distribution
Growth

Appendix
Appendix

Maintain Stable Cash Flows: Comprehensive Hedging Program
56
1
As of September 30, 2014. Based on exposures as of Q3 2014
Executed Hedges by Product
1
Balance of
2014
Full Year 2015
Full Year 2016
Natural Gas/Ethane
73%
49%
-
C
3
to C
4
60%
29%
-
C
5
+/Condensate
88%
37%
23%

Maintain Stable Cash Flows: Comprehensive Hedging Program
57
Note:  WTI prices in $/bbl; WTI Natural Gas prices in $/MMbtu; all other prices in $/gallon
1
As of September 30, 2014. Based on exposures as of Q3 2014
Executed Hedges by Product
1
Balance of 2014
Full Year 2015
Full Year 2016
Bbls/d
Price
($/gal)
Bbls/d
Price
($/gal)
Bbls/d
Price
($/gal)
Propane
3,989
$1.05
1,900
$1.05
-
-
Normal Butane
1,600
$1.34
800
$1.19
-
-
Bbls/d
Price
($/Bbl)
Bbls/d
Price
($/Bbl)
WTI
5,036
$95.72
2,115
$90.10
$1,311
$84.48
Cushing to
Midland Basis
-
-
1,000
$(3.00)
-
-
MMbtu/d
Price
($/MMbtu)
MMbtu/d
Price
($/MMbtu)
Natural Gas
(Henry Hub)
45,043
$4.00
45,000
$3.89
-
-
Natural Gas
(Permian)
40,000
$4.10
24,932
$3.95
-
-
Natural Gas
(Panhandle)
20,000
$4.35
-
-
-
-

Eastern
FY 2015E Margin by Type
58
Mid-Continent
South Texas
Ark-La-Tex
Permian
19%
39%
41%
1%
Gas
NGL
Condensate
Fee
Helium
100%
Fee
36%
12%
23%
29%
0%
Gas
NGL
Condensate
Fee
6%
5%
5%
84%
Gas
NGL
Condensate
Fee
8%
4%
0%
88%
0%
Gas
NGL
Condensate
Fee

September 30, 2014
June 30, 2014
March 31, 2014
December 31, 2013
September 30, 2013
June 30, 2013
Net income (loss)
107
$                        
(4)
$                   
12
$                  
3
$                           
42
$                          
11
$                  
Add (deduct):
Operation and maintenance
129
93
78
76
78
73
General and administrative
36
54
33
24
13
18
Loss (gain) on asset sales, net
1
-
(2)
1
(1)
1
Depreciation and amortization
122
168
94
80
74
68
Income from unconsolidated affiliates
(53)
(47)
(43)
(32)
(37)
(31)
Interest expense, net
86
78
56
45
41
41
Loss on debt refinancing, net
(2)
-
-
-
-
7
Other income and deductions, net
2
7
(2)
(4)
(24)
7
Income tax benefit
4
1
(1)
-
2
(1)
Total Segment Margin
432
350
225
193
188
194
Non-cash (gain) loss from commodity derivatives
(17)
1
3
7
9
(12)
Segment margin related to the noncontrolling interest
(7)
(6)
(6)
(5)
(4)
(2)
Segment margin related to our ownership percentage in
Ranch JV
4
3
3
2
1
1
Adjusted Total Segment Margin
412
$                       
348
$                
225
$                
197
$                       
194
$                       
181
$                
Gathering and Processing Segment Margin
349
$                       
269
$                
166
$                
137
$                       
136
$                       
145
$                
Non-cash loss (gain) from commodity derivatives
(17)
1
3
7
9
(12)
Segment margin related to the noncontrolling interest
(7)
(6)
(6)
(5)
(4)
(2)
Segment margin related to our ownership percentage in
Ranch JV
4
3
3
2
1
1
Adjusted Gathering and Processing Segment Margin
329
267
166
141
142
132
Natural Gas Transportation Segment Margin
-
-
-
-
-
-
Contract Services Segment Margin
66
63
56
55
52
49
Natural Resources
18
20
2
-
-
-
Corporate Segment Margin
2
2
5
4
4
4
Inter-segment Eliminations
(3)
(4)
(4)
(4)
(4)
(4)
Adjusted Total Segment Margin
412
$                       
348
$                
225
$                
196
$                       
194
$                       
181
$                
($ in millions)
Three Months Ended
Non-GAAP Reconciliations
59

Non-GAAP Reconciliations
60
September 2014
June 30, 2014
March 31, 2014
December 31, 2013
September 30, 2013
June 30, 2013
Net income (loss)
107
$                  
(4)
$                 
12
$                   
2
$                             
42
11
Add:
Interest expense, net
86
                      
78
                  
56
                     
45
41
41
Depreciation and amortization
122
                    
168
                
94
                     
80
74
68
                     
Income tax expense (benefit)
4
                        
1
                    
(1)
                     
-
                               
2
                               
-
                   
EBITDA (1)
319
$                  
243
$              
161
$                 
127
$                         
159
$                         
120
$                 
Add (deduct):
Partnership's ownership interest in unconsolidated affiliates' adjusted EBITDA (2)(3)(4)(5)(6)(7)
86
                      
79
                  
75
                     
62
                             
66
                             
60
                     
Income from unconsolidated affiliates
(53)
                     
(47)
                 
(43)
                   
(32)
                           
(37)
                           
(31)
                   
Non-cash (gain) loss from commodity and embedded derivatives
(16)
                     
9
                    
4
                       
3
                               
(14)
                           
(4)
                     
Other income, net
8
                        
23
                  
8
                       
5
                               
(2)
                             
10
                     
Adjusted EBITDA
344
$                  
307
$              
205
$                 
165
$                         
172
$                         
155
$                 
(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
19
16
15
16
$                           
18
$                           
18
$                   
Add (deduct):
Depreciation and amortization
8
                        
10
                  
10
                     
9
                               
9
                               
9
                       
Interest expense, net
4
                        
3
                    
3
                       
3
                               
1
                               
-
                       
Loss on sale of asset, net
-
                         
-
                     
-
                       
(1)
                             
-
                               
-
                       
Impairment of property, plant and equipment
-
                         
-
                     
-
                       
-
                               
-
                               
-
                       
Other expense, net
-
                         
-
                     
-
                       
-
                               
-
                               
-
                       
Adjusted EBITDA
31
$                    
29
$                
28
$                   
27
$                           
28
$                           
27
$                   
Ownership interest
49.99%
49.99%
49.99%
49.99%
49.99%
49.99%
Partnership's interest in Adjusted EBITDA
15
$                    
14
$                
14
$                   
13
$                           
14
$                           
13
$                   
(3) 100% of MEP Joint Venture's Adjusted EBITDA and the Partnership's interest are calculated as follows:
Net income
21
$                    
22
$                
21
$                   
17
$                           
21
$                           
21
$                   
Add:
Depreciation and amortization
17
                      
17
                  
17
                     
17
                             
17
                             
17
                     
Interest expense, net
12
                      
13
                  
13
                     
13
                             
13
                             
13
                     
Adjusted EBITDA
50
$                    
52
$                
51
$                   
47
$                           
51
$                           
51
$                   
Ownership interest
50%
50%
50%
50%
50%
50%
Partnership's interest in Adjusted EBITDA
25
$                    
26
$                
26
$                   
24
$                           
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
104
$                  
89
$                
83
$                   
53
$                           
60
$                           
44
$                   
Add (deduct):
Depreciation and amortization
27
26
25
24
                             
21
                             
20
                     
Other (income) expense, net
2
                        
-
                 
1
                       
-
                           
1
                               
1
                       
Adjusted EBITDA
133
$                  
115
$              
109
$                 
77
$                           
82
$                           
65
$                   
Ownership interest
30%
30%
30%
30%
30%
30%
Partnership's interest in Adjusted EBITDA
40
$                    
35
$                
33
$                   
23
$                           
25
$                           
20
$                   
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
7
$                      
7
$                  
6
$                     
2
$                             
1
$                             
1
$                     
Add (deduct):
Depreciation and amortization
1
                        
3
                    
1
                       
1
                               
1
                               
1
                       
Other income, net
1
                        
-
                     
-
                       
-
                               
-
                               
-
                       
Adjusted EBITDA
9
$                      
10
$                
7
$                     
3
$                             
2
$                             
2
$                     
Ownership interest
33%
33%
33%
33%
33%
33%
Partnership's interest in Adjusted EBITDA
3
$                      
3
$                  
2
$                     
1
$                             
1
$                             
1
$                     
We acquired a 33.33% interest in Ranch Joint Venture in December 2011.
(6) 100% of Aqua JV's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net loss
(2)
$                     
(3)
$                 
-
$                     
-
$                             
-
$                             
-
$                     
Add (deduct):
Depreciation and amortization
4
                        
3
                    
-
                       
-
                               
-
                               
-
                       
Other income, net
-
                         
-
                     
-
                       
-
                               
-
                               
-
                       
Adjusted EBITDA
2
$                      
-
$                   
-
$                     
-
$                             
-
$                             
-
$                     
Ownership interest
51%
51%
51%
51%
51%
51%
Partnership's interest in Adjusted EBITDA
1
$                      
-
$               
-
$                 
-
$                         
-
$                         
-
$                 
We acquired a 51% interest in Aqua JV in March 2014.
(7) 100% of Coal Handling JV's Adjusted EBITDA and the Partnership's interest are  calculated as follows:
Net income
2
$                      
1
$                  
-
$                     
-
$                             
-
$                             
-
$                     
Add (deduct):
Depreciation and amortization
1
                        
1
                    
-
                       
-
                               
-
                               
-
                       
Other income, net
-
                         
-
                     
-
                       
-
                               
-
                               
-
                       
Adjusted EBITDA
3
$                      
2
$                  
-
$                     
-
$                             
-
$                             
-
$                     
Ownership interest
50%
50%
50%
50%
50%
50%
Partnership's interest in Adjusted EBITDA
2
$                      
1
$                  
-
$                 
-
$                         
-
$                         
-
$                 
We acquired a 50% interest in Coal Handling JV in March 2014.
($ in millions)
Three Months Ended

Non-GAAP Reconciliations
61
September 30, 2014
June 30, 2014
March 31, 2014
December 31, 2013
September 30, 2013
June 30, 2013
Net cash flows provided by operating activities
293
$                         
90
$                 
187
$                  
59
$                          
183
$                         
112
$               
Add (deduct):
Depreciation, depletion and amortization, including debt
issuance cost amortization and bond premium write-off and
amortization
                            (99)
                 (167)
(97)
                    
(82)
                          
(75)
                           
(68)
                 
Income from unconsolidated affiliates
                              53
                    47
43
                     
32
                            
37
                            
31
                  
Derivative valuation change
                              16
                      4
(17)
                    
(3)
                            
14
                            
1
                    
Loss on asset sales, net
                              (1)
                      -
2
                       
(1)
                            
2
                              
(1)
                   
Unit-based compensation expenses
                              (3)
                    (3)
(2)
                      
(2)
                            
(2)
                             
(1)
                   
Cash flow changes in current assets and liabilities:
Trade accounts receivables, accrued revenues, and related
party receivables
                              28
                    (4)
21
                     
23
                            
32
                            
27
                  
Other current assets and other current liabilities
                            (26)
                      9
(35)
                    
28
                            
(25)
                           
137
                 
Trade accounts payable, accrued cost of gas and liquids,
related party payables and deferred revenues
                           (109)
                    84
(48)
                    
(20)
                          
(89)
                           
(57)
                 
Distributions of earnings received from unconsolidated
affiliates
                            (51)
                  (53)
(43)
                    
(33)
                          
(37)
                           
(35)
                 
Other assets and liabilities
                                6
                  (11)
1
                       
1
                             
2
                              
(135)
               
Net (Loss) Income
107
$                        
(4)
$                 
12
$                   
2
$                           
42
$                          
11
$                
Add:
Interest expense, net
                              86
                    78
56
                     
45
                            
41
                            
41
                  
Depreciation and amortization
                            122
                  168
94
                     
80
                            
74
                            
68
                  
Income tax expense (benefit)
                                4
                      1
(1)
                      
-
                              
2
                              
-
                     
EBITDA
319
$                        
243
$              
161
$                 
127
$                       
159
$                        
120
$              
Add (deduct):
Partnership's interest in unconsolidated affiliates' adjusted
EBITDA
                              86
                    79
75
                     
62
                            
66
                            
60
                  
Income from unconsolidated affiliates
                            (53)
                  (47)
(43)
                    
(32)
                          
(37)
                           
(31)
                 
Non-cash loss (gain) from commodity and embedded
derivatives
                            (16)
                      9
4
                       
3
                             
(14)
                           
(4)
                   
Other income, net
                                8
                    23
8
                       
5
                             
(2)
                             
10
                  
Adjusted EBITDA
344
$                        
307
$              
205
$                 
165
$                       
172
$                        
155
$              
Add (deduct):
Interest expense, excluding capitalized interest
                            (97)
                  (87)
(86)
                    
(51)
                          
(40)
                           
(46)
                 
Maintenance capital expenditures
                            (24)
                  (15)
(25)
                    
(18)
                          
(9)
                             
(13)
                 
SUGS Contribution Agreement adjustment *
                      -
-
                       
-
                          
-
                           
9
                    
PVR DCF contribution
                                -
                      -
83
                     
-
                          
-
                           
-
                 
Proceeds from asset sales
                                1
                      2
5
                       
2
                             
-
                           
5
                    
Other adjustments
                              (9)
                      -
-
                       
(4)
                            
(8)
                             
(9)
                   
Distributable cash flow
215
$                        
207
$              
182
$                 
94
$                         
115
$                        
101
$              
* Includes an adjustment to DCF related to the historical SUGS operations for the time period prior to the Partnership's acquisition.
($ in millions)
Three Months Ended

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