EX-99.1 2 ex99-1.htm COPANO ENERGY, L.L.C. 2011 ANALYST MEETING PRESENTATION ex99-1.htm
2011 Analyst Meeting

June 16, 2011

NASDAQ: CPNO
 
 
 
Disclaimer
This presentation includes “forward-looking statements,” as defined in the federal securities laws.
Statements that address activities or events that Copano believes will or may occur in the future are
forward-looking statements. These statements include, but are not limited to, statements about future
producer activity and Copano’s total distributable cash flow and distribution coverage. These statements
are based on management’s experience and perception of historical trends, current conditions, expected
future developments and other factors management believes are reasonable.
Important factors that could cause actual results to differ materially from those in the forward-looking
statements include the following risks and uncertainties, many of which are beyond Copano’s control:
the volatility of prices and market demand for natural gas and natural gas liquids; Copano’s ability to
continue to obtain new sources of natural gas supply and retain its key customers; the impact on
volumes and resulting cash flow of technological, economic and other uncertainties inherent in
estimating future production, producers’ ability to drill and successfully complete and attach new natural
gas supplies and the availability of downstream transportation systems and other facilities for natural
gas and NGLs; higher construction costs or project delays due to inflation, limited availability of required
resources, or the effects of environmental, legal or other uncertainties; general economic conditions;
the effects of government regulations and policies; and other financial, operational and legal risks and
uncertainties detailed from time to time in Copano’s quarterly and annual reports filed with the
Securities and Exchange Commission.
 
Copano undertakes no obligation to update any forward-looking statements, whether as a result of new
information or future events.
2
 
 
 
Agenda
3
  Corporate Overview & Strategy Bruce Northcutt
  President and CEO
  Oklahoma Segment Sharon Robinson
  SVP and President, Oklahoma and Rocky Mountains
  Rocky Mountains Segment Sharon Robinson
  SVP and President, Oklahoma and Rocky Mountains
  Texas Segment Jim Wade
  SVP and President, Texas
  M&A Discussion John Goodpasture
  SVP, Corporate Development
  Financial Discussion  Carl Luna
  SVP and CFO
  Conclusions Bruce Northcutt
  President and CEO
 
 
 
Corporate Overview & Strategy
Bruce Northcutt
4
 
 
 
5
1992
John Eckel
founds
Copano,
acquires
Copano Bay
system
2001
Houston
Central plant
acquisition
2004
First
midstream
LLC to IPO
2005
ScissorTail
Energy
acquisition
2007
Cimmarron
and Cantera
acquisitions
2010
Initiation of
Eagle Ford
Shale
strategy
  Founded in 1992, Copano has grown from a single 23-mile pipeline
 to a successful independent midstream natural gas company
  Copano has continued to grow its asset base over time through
 acquisitions and organic growth projects
Experienced Operator with a History
of Growth
 
 
 
Business Strategy
  To build a diversified midstream company with scale and
 stability of cash flows, above-average returns on invested
 capital and “investment-grade quality” distributions
6
  Key tenets of our business strategy:
 ■ Develop and exploit flexibility in our operations
 ■ Expand midstream services menu outside traditional gathering and processing
 ■ Execute on growth opportunities and acquisitions
 ■ Reduce sensitivity to commodity prices
 ■ Maintain a strong balance sheet and access to liquidity
 
 
 
Copano’s Key Strengths
  Founded in 1992 as an independent midstream company
  Experienced operator in liquids-rich natural gas plays
  Six executive management members with 166 combined years of industry experience
7
Experienced
Operator /
Seasoned Team
Strong Balance
Sheet with
Access to
Liquidity
Strategic and
Diverse Asset
Base
Significant
Organic Growth
Opportunities
  Significant position in Eagle Ford Shale and North Barnett Shale Combo
  One of the largest gatherers of associated gas in Eastern Oklahoma
  Large gatherer of Powder River Basin gas with access to Niobrara and Frontier gas
  Upon completion of processing expansion, Houston Central complex will be largest
 plant in Texas
  Over $400 million in growth projects in 2011 (1) - majority in Eagle Ford Shale
  Investments in announced growth projects target 5x multiple
  Opportunities beyond traditional gathering and processing
  New $700 million revolver in place
  $300 million TPG Capital preferred equity
  Improving cash flow expected from projects due to be completed this year
Long-term
Contracts and
Improving
Contract Mix
  DK pipeline, Eagle Ford Gathering JV and Saint Jo system approximately 80%
 contracted
  Average contract length for Eagle Ford Shale and North Texas Barnett Combo
 approaching 9 years
  Contract mix expected to be two-thirds fee-based by end of 2012
  Includes Copano’s net share for unconsolidated affiliates.
 
 
 
Key Personnel Additions
  Adding depth and experience in order to better execute on our
 business strategy and support future growth
 ■ Senior management additions
 ● John Goodpasture - Senior Vice President, Corporate Development
 ● Jim Wade - Senior Vice President and President and Chief Operating Officer,
 Texas
 ■ Other key hires
 ● Rex Prosser - Senior Director, Environmental, Health and Safety
 ● Rob Schaefer - Director, NGL Marketing and Logistics, Texas
 ● Cody Deru - Director, Gas Processing, Texas
8
 
 
 
Operating Segments
  Texas
 ■ Conventional, Eagle Ford Shale and
 North Barnett Shale Combo play
  Oklahoma
 ■ Conventional, Hunton de-watering
 play, Woodford Shale and
 Mississippi Lime
  Rocky Mountains
 ■ Powder River Basin
9
 
 
 
“High-Octane” Plays
  Copano currently has assets in four of the most active U.S.
 resource plays - Eagle Ford Shale, North Barnett Shale Combo,
 Mississippi Lime and Powder River Basin Niobrara
10
Source: ITG (formerly RSEG).
Copano assets
 
 
 
Rich Gas Benefit
  Upstream economics continue to drive producers toward oil and
 liquids-rich plays
  Copano has significant experience handling liquids-rich gas
  Significant additional infrastructure is needed to properly handle
 the liquids
11
 
 
 
Eagle Ford Shale Landscape
  Significant producer activity with large
 upstream representation
 ■ Approximately 170 rigs currently running in
 the Eagle Ford Shale
 ■ Significant investment by offshore firms
 encouraging activity
 ■ Lack of completion crews and liquids-handling
 capabilities limiting near-term growth
  Many competitors in midstream space,
 but early-movers and those with
 existing infrastructure are advantaged
 ■ Producers fostering competition (i.e., multiple
 midstream providers desired)
 ■ Midstream providers with full-service
 capabilities lead the pack
 ● Producers require both natural gas and
 liquids solutions
12
Used with permission of Oil & Gas Journal
 
 
 
Eagle Ford Shale NGL Volume Growth
Outlook
  Volume growth driven by oil and rich gas economics
 ■ Post-processing NGLs could be over 320,000 Bbls/d by year-end 2020(1)
13
Source: ITG (formerly RSEG).
  Source: ITG (formerly RSEG).
 
 
 
Solid Core Business Growth
14
  From 1Q 2009 to 1Q 2011, Texas and Oklahoma operating
 segment gross margins has increased approximately 95%
 
 
 
Significant Organic Growth
Opportunities
  Current areas of focus:
 ■ Eagle Ford Shale
 ■ North Barnett Shale Combo play
 ■ Woodford Shale
 ■ Mississippi Lime
  Total 2011 growth capex of over $400 million(1)
 ■ Expected to be invested at 5x multiple
  Already moving ahead with a new phase of Eagle Ford Shale
 infrastructure
 ■ Houston Central complex processing expansion (400 MMcf/d cryo)
 ■ Newly announced 100 MMcf/d processing agreement with Williams Partners at
 Markham plant
  Opportunities for future growth include:
 ■ Niobrara
 ■ Condensate/crude oil logistics
 ■ Acquisitions
15
  Includes Copano’s net share for unconsolidated affiliates.
 
 
 
Other Midstream Value Chain
Opportunities
  Further expansion into other businesses in the midstream value
 chain will help drive long-term value and improve stability of cash
 flows
16
 
 
 
Changing Contract Structure Results in
More Predictable Cash Flows
  New projects are supported predominately by long-term, fee-based
 contracts with either volume commitments or acreage dedications
 ■ DK pipeline and extension
 ■ Eagle Ford Gathering JV
 ■ Fractionation expansion and Houston Central complex processing expansion
 ■ Saint Jo plant (North Barnett Shale Combo)
 ■ Cyclone Mountain system (Woodford Shale)
  Fee-based contracts require little or no hedging, which should
 reduce risk management costs
  Much of base business also backed by long-term contracts
 ■ Hunton de-watering play
 ■ Powder River Basin
 
 
 
Liquidity and Capital for Growth Plan
  Approaching completion of several large capital projects with
 outlook for increasing cash flow following their completion
 ■ Volume growth in North Barnett Shale Combo steadily increasing
 ■ DK pipeline throughput averaging 115,000 MMBtu/d and awaiting completion
 of the DK extension and Houston Central complex fractionation expansion to
 ramp up volumes
 ■ Eagle Ford Gathering JV pipelines, Liberty NGL pipeline and fractionation
 expansion to be completed second half of 2011
  Current projects pre-funded with preferred equity in 2010
  Recently completed expansion and extension of our revolver to
 increase liquidity
  Improving distribution coverage is expected 4Q 2011 and 2012
  Board likely to consider distribution increases when coverage
 reaches 120% - 130%
 ■ More stable long-term cash flows should allow for long-term coverage target
 below 120%
 
 
 
Market Trends
  Most drilling concentrated in new, unconventional shale plays
 ■ Significant midstream infrastructure required
  Due to liquids prices (oil and NGLs), upstream sector focused on
 rich gas and oil plays
  Regional basis differentials have been disrupted both for natural
 gas and liquids
 ■ Creates new midstream growth opportunities
  Eagle Ford Shale is currently the best-situated U.S. shale play
 ■ Regulatory environment familiar with industry
 ■ Land owners are more industry-friendly
 ■ Some existing infrastructure already in place
 ■ Proximity to large consuming market, industrial load and petrochemical
 markets
19
 
 
 
Copano’s Outlook on Commodity Prices
  We manage our business for performance through wide-ranging
 commodity price environments
 ■ Contracting
 ■ Hedging
  We expect natural gas prices to stay soft in the near term
  While oil has strengthened over the last year, potential demand
 management or demand destruction is a risk
 ■ Our view is that oil prices will continue to remain relatively strong
  NGL prices have remained strong due to demand for lighter
 feedstocks
 ■ While prices for C3+ are expected to remain strong, the forward curve
 suggests C2 will soften going forward
 ■ The differential between Conway and Mont Belvieu will remain wide until
 more capacity is built (e.g., ONEOK Sterling III and DCP Southern Hills
 pipeline)
 ■ NGL supply/demand balance likely to be dynamic for the foreseeable future
20
 
 
 
Executing Our Business Strategy
  Eagle Ford Shale, North Barnett Shale Combo, Woodford
 Shale and Mississippi Lime
  Acquisition of the Harrah and Davenport plants
21
Organic Growth and
Bolt-on Acquisition
Maintaining Strong
Balance Sheet
Reduce Sensitivity
to Commodity
Prices
Flexibility in
Operations
  Long-term, fee-based contracts
  More fee-based contracts reduce hedging requirements
  Access to multiple NGL markets
  Ability to fractionate or produce y-grade product
  Multiple plant residue alternatives
  March 2010 equity offering
  TPG Capital preferred equity investment
  Senior notes refinancing
  Expanded revolver
Expand Midstream
Services Menu
  Restart and expansion of Houston Central complex fractionator
  Purity ethane and propane pipeline service
  Y-grade service through the Liberty pipeline
 
 
 
Oklahoma Segment
Sharon Robinson
22
 
 
 
Oklahoma Overview
  Comprised of 9 gathering
 systems
 ■ Approximately 4,000 total miles of
 active pipelines
 ■ 7 processing plants - 236 MMcf/d
 processing capacity
 ● Paden (cryo/ref)  100 MMcf/d
 ● Harrah (cryo)  38 MMcf/d
 ● Southern Dome (ref)  30 MMcf/d
 ● Glenpool (cryo)  25 MMcf/d
 ● Milfay (ref)   15 MMcf/d
 ● Burbank (ref)  10 MMcf/d
 ● Davenport (idle cryo)
   18 MMcf/d
 ■ 3 amine treating facilities
 ● 310 GPM of capacity
 ■ 1 nitrogen rejection unit
 ● 48 MMcf/d of capacity (Paden)
23
 
 
 
Stroud System
  Gathering and processing
 ■ 982 miles (2” - 16” in diameter)
 ■ Throughput capacity of
 approximately 121 MMcf/d
 ■ Current throughput of
 approximately 97 MMcf/d
 ■ Processing - 156 MMcf/d capacity
 ● Paden - 100 MMcf/d
 ● Harrah/Davenport - 56 MMcf/d
 ■ Nitrogen rejection facility - 48
 MMcf/d
 ■ Residue gas delivered to Enogex
 and Oklahoma Gas Transmission
 ■ NGLs delivered to ONEOK
 ■ Condensate sold via trucks
24
 
 
 
Stroud System
  Acquired Harrah plant (April 2011)
 ■ Processing plants
 ● Harrah with total capacity of 38 MMcf/d (two plants)
 ● Davenport with total capacity of 18 MMcf/d (idle)
 ■ Lowest cost expansion for processing in Stroud area
 ■ Decreased dependence on third-party processing
 ■ Potential growth from new and existing producers
25
 
 
 
Stroud System
  Primary producing formation - Hunton de-watering
 ■ Horizontal rich gas drilling play in central/eastern Oklahoma
 ■ Approximately 340 Hunton wells are connected to Copano’s Stroud system
26
Hunton Well Profile
Vertical depth:
4,500 ft. - 4,800 ft. (laterals of
3,000 ft. - 7,000 ft.)
Drilling costs:
$2.5 million - $3 million
IP rate:
500 Mcf/d (peak of 750 Mcf/d -
1,000 Mcf/d)
Water:
Initially as high as 10,000 Bbls/d
that decline over life of well
Gas quality:
Average of 1,300 Btu
6% nitrogen
Spacing:
640 acres
 
 
 
Stroud System
  Primary producers with proven track records
 ■ New Dominion LLC (NDL)
 ■ Equal Energy
  Volume outlook
 ■ Expected to increase over the next few years as a result of:
 ● Continued drilling activity by NDL and Equal Energy
 ● New producers entering area
 ● Potential exploitation of additional zones
 ● 3 rigs currently running
 ● Expecting 20 - 25 wells to be drilled in 2011
27
 
 
 
Mountain Systems
  Gathering
 ■ Comprised of three systems
 ● Cyclone Mountain - Pittsburg
 County
 ● Blue Mountain - Latimer County
 ● Pine Mountain - Pittsburg and
 Atoka Counties
 ■ 195 miles (2” - 20” in diameter)
 ■ Throughput capacity of
 approximately 154 MMcf/d
 ■ Current throughput of
 approximately 96 MMcf/d
 ■ 310 GPM of treating capacity
 ● Additional 150 GPM treater in
 service by October 2011
 ■ Market deliveries to CenterPoint
 and Enogex
 ■ Low and high pressure service
28
 
 
 
Mountain Systems
  Primary producing formation - Woodford Shale
 ■ Located in southeastern Oklahoma
 ● Rich gas - western half
 ● Lean gas - eastern half
29
Woodford Shale Well Profile
Vertical depth:
8,000 ft. - 12,600 ft. (laterals
of 4,500 ft. - 7,500 ft.)
Drilling & completion cost:
$4.5 million - $5.5 million
IP rate:
4,000 Mcf/d - 6,500 Mcf/d
(peak of 10,000 Mcf/d)
Reserves per well:
4.5 Bcf - 6.0 Bcf
Gas quality:
940 Btu
3.5% - 6.5% CO2
 
 
 
Mountain Systems
  Primary producers
 ■ PetroQuest Energy
 ■ XTO Energy
 ■ Continental Resources
 ■ Antero Resources
  Volume outlook
 ■ Volumes are expected to significantly increase in 2011 due to Woodford
 Shale development on Cyclone Mountain system
 ● Major producer is very encouraged by results
 ● Improved fracturing techniques have increased IP rates and reduced
 drilling costs
 ● 3 rigs currently running with 1 additional rig moving in
 ● Expect approximately 20 additional wells to be drilled in the balance of
 2011
  Contracts are primarily fee-based
  
30
 
 
 
Osage System
  Gathering and processing
 ■ 563 miles (2” - 8” in diameter)
 ■ Throughput capacity of
 approximately 32 MMcf/d
 ■ Current throughput of
 approximately 18 MMcf/d
 ■ Processing - Burbank plant
 (propane refrigeration)
 ● 10 MMcf/d capacity
 ■ Residue gas delivered to Post
 Rock KPC Pipeline
 ■ NGLs transported via truck
 ■ Low pressure service
31
 
 
 
Osage System
  New primary producing formation - Mississippi Lime
 ■ Emerging play, horizontal drilling targeted area (northern Oklahoma and
 southern Kansas)
 ■ Copano assets are well positioned in Noble, Pawnee, Payne and Osage Counties,
 where leasing has been very active and drilling activity is projected to increase
 in the second half of 2011 and into 2012
32
Mississippi Lime Well Profile
Vertical depth:
4,000 ft. - 6,000 ft.
Drilling costs:
$1.0 million - $2.5 million
IP rates:
Initial results vary
40 Mcf/d - 700 Mcf/d
Gas quality:
1,100 Btu - 1,600 Btu
8% - 15% nitrogen
 
 
 
Osage System
  Existing primary producers
 ■ CEP Mid-Continent
 ■ Chaparral Energy
 ■ Mt. Dora Energy
 ■ Spyglass Energy
  Gas quality
 ■ 60/40 ratio of lean to rich gas
 ■ Current producing trend is toward the rich gas
  Volume outlook
 ■ Rich gas volumes expected to increase based on the leasing/permitting
 activity in the Mississippi Lime
33
 
 
 
Osage System - Mississippi Lime
  Leasing activity
 ■ Over 800,000 acres have been
 leased within the last 12 months in
 Osage, Noble and Pawnee Counties
 ● 82% of these acres are in close
 proximity to Copano’s assets
 ■ Over a dozen producers actively
 leasing, including:
 ● SandRidge Energy
 ● Ram Energy
 ● Spyglass Energy
 ● Chaparral Energy
 ● Sullivan & Company
34
 
 
 
Osage System - Mississippi Lime
  Gathering and processing capabilities
 ■ Approximately 150 miles of idle pipe, acquired in 2007, is available for
 activation and integration into the Osage system
 ■ Processing
 ● Potential Burbank plant expansion
 ● Paden plant
 ● Third-party processing
  Producer activity
 ■ Producers have indicated the number of wells drilled in this play will be
 significant once area is proved out
  Volume outlook
 ■ Crude oil play with low volume, associated gas
 ■ Active leasing and permitting activity
 ■ Rich gas with shallow declines and high nitrogen
35
 
 
 
Growth Opportunities - Stroud System
  Producers in the Hunton are looking to develop additional zones
  Over the next 2 - 3 years, there is the potential for as many as 4 -
 6 additional rigs move into the area currently served by the Stroud
 system
  Copano’s existing midstream infrastructure is a key competitive
 advantage long-term
 ■ Barriers to entry for other midstream companies are high both from a
 gathering infrastructure and gas handling perspective
36
 
 
 
Growth Opportunities - Mountain
Systems
  Copano is strategically positioned with large diameter pipe in this
 area of the Woodford Shale
  Average system volumes have increased approximately 25% since
 the beginning of 2011 to 85 MMcf/d on Cyclone Mountain system
 (95% is Woodford Shale)
  Major Woodford Shale producer behind the Cyclone Mountain
 system currently evaluating opportunities to bring in an additional
 rig by year-end 2011
  Cyclone Mountain is expected to be at capacity by mid-2012
 ■ Opportunity to invest capital on expanding system when volumes increase
37
 
 
 
Growth Opportunities - Mississippi Lime
  Many producers are very active in leasing acreage
  Existing Copano infrastructure gives us a strategic advantage
  Predominant oil play points to rapid development of reserves
 independent of price curve for natural gas
 ■ Associated natural gas will require processing and treating services
38
 
 
 
Rocky Mountains Segment
Sharon Robinson
39
 
 
 
Rocky Mountains
  Gathering and treating
 ■ Two gathering systems
 ● Bighorn Gas Gathering (51%
 managing member interest)
 ● Fort Union Gas Gathering (37.04%
 managing member interest)
 ■ 591 miles (6” - 24” in diameter)
 ■ Throughput capacity of approximately
 1.6 Bcf/d
 ■ Current throughput of approximately
 550 MMcf/d
 ■ 1,500 GPM treating capacity
 ■ 53,000 HP of compression
 ■ Current focus area is the Powder River
 Basin
 ● Estimated gas reserves in place of
 over 20 Tcf
40
 
 
 
Bighorn Gas Gathering
  Gathering
 ■ 273 miles of pipeline (6” - 24” in
 diameter)
 ■ Throughput capacity of
 approximately 300 MMcf/d
 ■ Current throughput of
 approximately 143 MMcf/d
 ■ 53,000 HP of compression
 ■ Low and high pressure service
 ■ Gas quality - 100% lean gas (coal
 bed methane - no processing)
  Primary producers
 ■ Marathon
 ■ High Plains Gas
 ■ JM Huber
 ■ Western Gas
 ■ Summit
41
 
 
 
Fort Union Gas Gathering
  Gathering and treating
 ■ High pressure gas gathering system
 ■ Three parallel 24”, 106-mile pipelines
 ■ 1.25 Bcf/d of throughput capacity
 ■ 1,500 GPM of treating capacity
 ■ Market deliveries to WIC, CIG, and
 Kinder Morgan
 ■ Gas quality - 100% lean gas with
 treating for CO2 removal (no
 processing)
42
 
 
 
Rocky Mountains Volume Outlook
  Drilling activity minimal due to pricing environment
 ■ Producer discussions indicate sustained pricing above $4.30/MMBtu needed to
 stimulate drilling
  Consolidation among producers has begun; could signal potential
 increase in producer activity
 ■ Producers will have a lower cost basis allowing for more activity
 ■ Producers indicate they will start de-watering already drilled wells
 ■ Significant number of wells drilled, but not de-watered
  Fort Union volumes impacted by start-up of TransCanada Bison
 pipeline in January 2011
 ■ Due to long-term contractual requirements, do not expect material impact to
 Copano’s Adjusted EBITDA
43
 
 
 
Growth Opportunities - Rocky
Mountains
  Southern Niobrara (DJ Basin area)
 ■ Centered in southeastern Wyoming and
 northeastern Colorado
 ■ Growing producer activity, with mixed
 results
 ■ Primarily an oil-directed play with
 associated rich gas
  Northern Niobrara (Powder River
 Basin area)
 ■ Centered in central and eastern Wyoming,
 adjacent to Fort Union Gas Gathering
 ■ Primarily an oil-directed play with
 associated gas
 ■ Significant leasing activity
 ■ Producer results have been positive
 ■ Major producers include: Chesapeake,
 Marathon, EOG Resources, Samson,
 Cirque Resources and Mack Energy
44
 
 
 
Conclusions - Oklahoma & Rocky
Mountains
  Oklahoma
 ■ Exploit our gathering and processing footprint
 ■ Continue to pursue growth opportunities in the Woodford Shale and Mississippi
 Lime
  Rocky Mountains
 ■ Consolidation and restructuring by producers
 ■ Actively engaged in the emerging Niobrara play
45
 
 
 
Texas Segment
Jim Wade
46
 
 
 
Copano’s Texas Operations
  Approximately 2,000 miles of
 natural gas pipelines
  260 miles of NGL pipelines
  1 Bcf/d processing capacity
 ■ Houston Central complex
 ■ Saint Jo
 ■ Lake Charles (idle)
  22,000 Bbls/day of fractionation
 capacity
  Current service throughput of
 approximately 700,000 MMBtu/d
47
 
 
 
Primary Focus Areas in Texas
  Northern Eagle Ford Shale
 ■ DK pipeline and extension
 ■ Live Oak / Fashing system
 ■ Live Oak, DeWitt, Karnes and
 Lavaca Counties
  Southern Eagle Ford Shale
 ■ Eagle Ford Gathering LLC, a joint
 venture between Copano and Kinder
 Morgan
 ■ LaSalle, McMullen, Dimmitt and
 Webb Counties
  North Barnett Shale Combo play
 ■ Saint Jo system
 ■ Montague and Cook Counties
  Other Texas systems
48
 
 
 
Copano’s Eagle Ford Shale Strategy
  Utilize existing assets as a platform to provide additional
 midstream solutions for rich Eagle Ford Shale production well in
 excess of 1 Bcf/d of gas and over 100,000 Bbls/d of NGLs
49
  Existing assets
 ■ Gathering
 ■ Processing
 ■ Fractionation
 ■ NGL transportation
  Execution of this strategy is
 well underway
 
 
 
Northern Eagle Ford Shale
  DK pipeline
 ■ Capacity of 225,000 MMBtu/d
 ● Current throughput of
 approximately 115,000 MMBtu/d
 ■ 38 miles of 24” pipe placed into full
 service October 2010
 ■ Services the most prolific rich gas
 window in the Eagle Ford Shale
 ■ Key producer contracts with
 Abraxas, GeoSouthern, Petrohawk,
 Pioneer, Riley and others
 ■ Existing pipeline capital investment
 of $48 million
  Existing Fashing / Live Oak
 ■ Capacity of 100,000 MMBtu/d
 ■ Current Eagle Ford throughput of
 approximately 17,000 MMBtu/d
50
 
 
 
Northern Eagle Ford Shale
  DK extension
 ■ February 2011 - announced
 extension of existing pipeline back
 to Houston Central complex
 ● Additional 58 miles of 24” pipe
 ■ Loops Kinder Morgan’s Index 50
 pipeline, effectively boosting
 pipeline capacity to Houston
 Central complex
 ■ Extension to Houston Central
 complex will increase pipeline
 capacity to 350,000 MMBtu/d
 ■ Additional capital investment of
 $100 million
51
 
 
 
Southern Eagle Ford Shale
  Eagle Ford Gathering (EFG)
 ■ 50/50 JV with Kinder Morgan
  EFG pipeline
 ■ 117 miles of 30” and 24” pipe -
 currently under construction
 ■ Nominal capacity of 600,000
 MMBtu/d
 ■ Long-term, fee-based contracts
 with aggregate volume
 commitments approaching 500,000
 MMBtu/d
 ● SM Energy
 ● Chesapeake
 ● Anadarko
 ■ Net capital investment of $87.5
 million
52
 
 
 
EFG Crossover Project
  Crossover project
 ■ 66 miles of 24” and 20” pipe
 connecting Kinder Morgan’s Index
 50 and Tejas 30” pipelines to
 Formosa
 ● Nominal pipeline capacity of
 400,000 MMBtu/d
 ■ Allows an incremental 210,000
 MMBtu/d of gas to flow on EFG
 30” pipeline
 ■ Processing, fractionation and
 product sales at Formosa’s Point
 Comfort complex
 ■ Net capital investment of $50
 million
53
 
 
 
EFG Crossover Project Extension
  Extension to Williams Partners’
 Markham plant
 ■ Long-term contract with Williams
 Partners’ to initially process 100
 MMcf/d with an option to increase
 to 200 MMcf/d
 ■ EFG constructing 7 miles of 20”
 pipe connecting Kinder Morgan’s
 Tejas 30” pipeline to Markham
 plant (plus compression)
 ● Allows for full utilization of EFG
 crossover line nominal capacity
 of 400,000 MMBtu/d
 ● Net capital investment of $13.5
 million
 ■ Copano to construct 8-mile, 6”
 NGL pipeline from Markham plant
 to Liberty NGL pipeline
 ● Total capital investment of $5.5
 million
54
 
 
 
Houston Central Complex
  Current capacity of 700 MMcf/d
 ■ 500 MMcf/d of lean oil processing
 ■ 200 MMcf/d of cryogenic processing
  Multiple residue interconnects
 ■ Anticipated additional connection - Tres Palacios storage and header system
  Cryogenic processing expansion of 400 MMcf/d in process
 ■ Improves NGL recoveries
 ■ Allows base loading of cryogenic plants with spillover to lean oil plant
 ■ Total capital investment of $145 million
55
 
 
 
Houston Central Complex
  Fractionation expansion
 ■ Responding to increased
 producer demand, liquids
 handling capacity at Houston
 Central complex will double
 ■ Fractionation expansion from
 22,000 Bbls/d to 44,000
 Bbls/d
 ● All ethane and propane will
 move to Dow through
 Copano purity pipelines
 ■ Total capital investment of
 $66 million
 ● Includes fractionation
 facilities and related plant
 upgrades and product
 pipeline expansions
56
 
 
 
Liberty NGL Pipeline
 ■ Total capacity of 75,000 Bbls/d
 ■ Constructed through 50/50 JV
 with Energy Transfer
57
  Long-term fractionation and product
 sales agreement with Formosa on
 favorable terms
 ■ Initial access to a minimum of 5,000
 Bbls/d - 7,000 Bbls/d following Liberty
 NGL pipeline completion
 ■ Upon completion of Formosa’s
 fractionation expansion, will have up to
 37,500 Bbls/d of firm capacity starting
 1Q 2013 for a 15-year term
  Net capital investment of $26 million
 
 
 
Houston Central NGL Infrastructure
58
 
 
 
Gulf Coast Petrochemical Market Access
  Copano has access to Dow
 and, upon completion of the
 Liberty NGL pipeline,
 Formosa
 ■ Among the largest end users of
 NGLs in the U.S.
 ■ Taking into account announced
 expansions, Dow and Formosa’s
 combined steam cracker
 capacity is approximately 19%
 of total U.S. capacity(1)
59
  Source: Hodson Report.
 
 
 
Summary of Eagle Ford Shale
Infrastructure
60
  Total capital investment of over $500 million
  Well in excess of 1 Bcf/d of pipeline and processing capacity
  Exceeding 100,000 Bbls/d of fractionation capacity
  Access to multiple markets for residue gas and NGLs
 
 
 
Combined Eagle Ford Shale Map
61
 
 
 
Eagle Ford Shale Volume Outlook
  Copano’s total Eagle Ford Shale volumes have been averaging
 approximately 130,000 MMBtu/d
  EFG 30” pipeline expected to be in service September 2011 as
 originally forecasted
 ■ Interruptible volumes not expected to flow before September 2011 in-service
 date
  As our growth projects are completed, expect to see substantial
 volume increases on both wholly owned and joint venture assets in
 the second half of 2011 and beyond
62
 
 
 
Growth Opportunities - Eagle Ford Shale
  Potential extension of DK
 pipeline to Fashing / Live Oak
 system
 ■ Continues loop of Kinder
 Morgan’s Index 50 pipeline
 through the Eagle Ford Shale
 condensate window
 ■ Ties additional existing Copano
 gathering systems directly to
 Houston Central complex
 ■ Provides connectivity to the EFG
 crossover line for DK pipeline and
 Fashing / Live Oak volumes
63
 
 
 
Growth Opportunities - Eagle Ford Shale
  Potential extension of DK
 pipeline from Fashing / Live
 Oak system to EFG 30”
 pipeline in McMullen County
 ■ Completes loop of Kinder
 Morgan’s Index 50 pipeline
 ■ Increases exposure to remaining
 Eagle Ford Shale condensate
 window
 ■ Increases EFG 30” pipeline
 capacity and throughput
 capability with access to the EFG
 crossover line
64
 
 
 
Growth Opportunities - Eagle Ford Shale
  Crude oil / condensate
 initiatives under review
 ■ Convert existing Copano gas
 gathering line to crude service
 ■ Tie into markets, storage and
 loading docks in Corpus Christi
 ■ Utilize dual-line rights of way in
 the DK corridor to lay crude
 gathering system
 ■ Access Houston Ship Channel
 markets through existing
 interconnect with Teppco and
 possible future interconnect with
 Magellan’s Longhorn pipeline via
 Copano’s Brenham line
 ■ Generate substantial fee-based
 transportation revenue on as
 much as 125,000 Bbls/d of crude
 and condensate
65
 
 
 
Saint Jo System Map
66
 
 
 
Saint Jo System
  Saint Jo processing plant
 ■ 100 MMcf/d processing capacity
 ■ 1,200 GPM amine treater
 ■ Residue gas outlets
 ● NGPL
 ● Atmos
 ■ NGL outlet
 ● ONEOK Arbuckle pipeline
  Gathering system
 ■ 340 miles of pipe
 ■ 20,700 HP of compression
67
 
 
 
North Barnett Shale Combo
  Key producers with over 250,000 net acres
 ■ Oil directed drilling play
 ■ Currently 15 rigs running
  Multi-stage fracs performed on each well
68
North Barnett Shale Combo Well Profile
Vertical depth:
Approximately 9,000 ft.
Horizontal laterals:
Up to 6,000 ft.
Completed well cost:
Approximately $3 million
IP rate:
Up to 500 Bbls/d of oil and 1
MMcf/d of gas
Gas quality:
4 - 6 GPM
10% CO2
 
 
 
Saint Jo System - Major Producer
Contracts
  Long-term, fee-based contracts
  Firm commitment for 90,000 Mcf/d
  Current system throughput of approximately 67,000 Mcf/d
  Deficiency fees on any firm volumes not delivered
69
 
 
 
Growth Opportunities - Saint Jo System
  Expect to fill existing processing plant capacity by end of 2011
  Drilling activity by producers may warrant Saint Jo processing plant
 expansion
  Working with producers for volume commitments to support
 potential processing plant expansion
70
 
 
 
Growth Opportunities - Lake Charles
  200 MMcf/d cryogenic processing
 facility in Louisiana
  Previously processed rich gas from
 Trunkline’s LNG import facility
 ■ Idled in 2010 upon completion of
 Trunkline’s LNG processing plant
  Evaluated moving plant to expand
 Houston Central complex to handle
 Eagle Ford Shale growth
  Opportunity to restart and process
 up to 175 MMcf/d of 1,030 Btu
 mainline gas and minimal rich LNG
 “boil off” gas
 ■ Negotiating arrangements with several
 counterparties; anticipate restart
 before year-end 2011
71
 
 
 
Legacy Texas Systems
  Most legacy Texas systems tied
 to Houston Central complex via
 Kinder Morgan’s Index 50
 pipeline
 ■ Allows gathering of additional non-
 Eagle Ford Shale gas
  Asset optimization project
 underway on legacy Texas
 systems
 ■ Reviewing utilization and strategic
 use for each pipeline system
 ● Convert from gas service as
 needed to condensate, crude oil
 or NGL service
 ● Integrate into Eagle Ford Shale
 growth strategy
72
 
 
 
Conclusions - Texas
  Strategy for Eagle Ford Shale infrastructure to handle well in excess
 of 1 Bcf/d of gas and over 100,000 Bbls/d of NGLs is well underway
 ■ Significant new contracts underlie expansion projects
 ■ Contracts are long-term and fee-based
  Evaluating opportunity to utilize existing natural gas pipelines to
 provide crude oil / condensate service
  Saint Jo volume growth continues
 ■ Potential project to expand processing capacity
  Opportunity to restart Lake Charles plant
73
 
 
 
M&A Discussion
John Goodpasture
74
 
 
 
M&A Strategy
  Acquisitions have been an important part of Copano’s heritage and
 remain a key element of our current growth strategy
  The goal is to build a more diversified portfolio, adding scale and
 stability beyond what Copano’s organic initiatives will provide
 ■ Create operational synergies and/or “value linkage” with our existing assets
 ■ Enhance expertise and expand slate of services we provide our customers
 ■ Establish competitive positions in emerging areas
 ■ Grow fee-based component of our business (minimal commodity exposure)
  Current acquisition efforts focused on:
 ■ Leveraging core competencies
 ● Natural gas gathering, treating, processing, NGL fractionation, etc.
 ■ Entry into complementary lines of business
 ● NGL transmission/storage, crude and condensate gathering (via pipeline,
 truck, rail, and barge), natural gas transmission/storage, etc.
75
 
 
 
M&A Process
  Copano has a well-developed M&A process that includes:
 ■ Strategic assessment of target
 ● Gauge costs and probability of success
 ■ Rigorous due diligence effort
 ● Use outside expertise as required
 ■ Granular economic analyses
 ● Includes sound financing strategy consistent with our financial policy
 ■ Thorough review of all transaction documents
 ■ Comprehensive integration planning for all aspects of the business
76
 
 
 
Current M&A Market
  Very competitive, robust prices, seller-friendly contract terms
  Drilling activity has shifted to liquids-rich regions and significantly
 increased the value and prices paid for associated midstream
 assets (Eagle Ford, Marcellus, Bakken, Granite Wash, Niobrara,
 etc.)
  Midstream assets in lean gas plays are not commanding the same
 premium prices (Barnett, Haynesville, Powder River, etc.)
  Some producers are recapitalizing by selling producing properties
 and midstream facilities in non-core areas
  Significant investment in the E&P space by international firms is
 stimulating exploration and development
77
 
 
 
Current M&A Market
  New production in emerging areas has outpaced the growth of
 needed midstream infrastructure
  Liquids logistics capability (including storage, terminals, pipelines
 and truck/rail/barge transportation) is in short supply and is
 therefore particularly valuable
  Efficient delivery to a viable market is absolutely KEY
78
 
 
 
Financial Discussion
Carl Luna
79
 
 
 
1Q 2011 Results
80
 
 
 
Capitalization and Liquidity
81
 
 
 
New Revolving Credit Facility
  On June 10, 2011 closed a new $700 million five-year credit facility
 ■ Ability to increase facility to $850 million
  Added flexibility to financial covenants
 ■ Maximum total leverage ratio of 5.25x
 ■ Maximum senior secured leverage ratio of 4.00x
 ■ Minimum interest coverage ratio of 2.50x
 ■ Consolidated EBITDA definition to include pro forma EBITDA attributed to
 material projects, capped at 15% of Consolidated EBITDA
 ● Expected to add approximately $100 million in additional availability
  Grid pricing based on total leverage
 ■ Initial pricing of LIBOR plus 2.50%
 ■ Initial commitment fee of 0.375%
82
 
 
 
Financial Policy
  Target total leverage of 4.0x or below
83
 
 
 
2011 Capital Expenditure Plans
  Estimated capital spending over $400 million for wholly owned and
 JV expansion projects in 2011
  Once completed, capital investments should add approximately
 $60 - $70 million in incremental cash flow in 2012
84
 
 
 
2012 Capital Expenditure Plans
  2012 capital expenditures for announced projects include:
 ■ Approximately $110 million related to Houston Central complex processing
 expansion
  Additional 2012 capital expenditures will be driven by growth
 opportunities in Texas and Oklahoma and could include:
 ■ Southern extension of the DK pipeline
 ■ Crude oil and condensate projects in the Eagle Ford Shale
 ■ Expansion of the Cyclone Mountain system in the Woodford Shale
 ■ Expansion of the Saint Jo plant in north Texas
 ■ Gathering and processing expansions in the Mississippi Lime
 ■ Complementary acquisitions
  Will continue to target 5x multiple for new expansion projects and
 immediately accretive acquisitions
85
 
 
 
Shifting Contract Mix
  Continued shift towards a more fee-based contract mix
 ■ Eagle Ford Shale, North Barnett Shale Combo and Woodford Shale volume
 growth are key drivers
86
Contract Mix as a % of Gross Margin
 
1Q 2010
2Q 2010
3Q 2010
4Q 2010
1Q 2011
Fee-based
27%
33%
37%
38%
41%
Percentage-of-
proceeds
39%
31%
30%
32%
32%
Keep-
whole/Other
36%
33%
29%
34%
39%
Net hedging
-2%
3%
4%
-4%
-12%
Note: Includes Copano’s share of gross margin from unconsolidated affiliates. Approximate percentages based on Copano internal financial planning models.
 
 
 
Hedging Strategy
  Continued focus on option-based, product-specific hedging strategy
 ■ Reliance on hedging will decrease over time as contract mix changes
  2011 well hedged
 ■ Between 70% and 90% of ethane, propane, butane, natural gasoline and
 condensate price exposure is hedged
  2012 hedged near policy limits for all products except ethane
 ■ 80% of propane, butane, natural gasoline and condensate price exposure
 hedged
 ■ 20% of ethane price exposure hedged
  2013 hedging positions continue to be added
 ■ Between 40% and 60% of butane, natural gasoline and condensate price
 exposure hedged
 ■ 20% of propane price exposure hedged
 ■ No ethane hedges for 2013
87
 
 
 
Commodity-Related Margin Sensitivities
  Matrix reflects 1Q 2011 wellhead and plant inlet volumes, adjusted
 using Copano’s 2011 planning model
 
88
  Consists of Texas and Oklahoma Segment gross margins.
 
 
 
2011 Current Guidance
  General and administrative expenses:
 ■ $46 million - $48 million
  Operations and maintenance expenses:
 ■ $62 million - $64 million
  Interest expense:
 ■ $54 million - $56 million
  Maintenance capital expenditures:
 ■ $12 million - $14 million
  Non-cash amortization expense related to hedge portfolio:
 ■ $30 million - $31 million
89
 
 
 
Conclusions
Bruce Northcutt
90
 
 
 
Key Investment Highlights
  Experienced operator with a history of growth in an investor-friendly
 structure (no GP, no Incentive Distribution Rights)
  Seasoned team of motivated employees with strong experience in
 project development and handling liquid-rich plays
  Continued solid growth in core business
  Nearing completion of significant growth projects in resource plays -
 backed by attractive long-term contracts
  Quality and diverse asset base that provides operational flexibility to
 both Copano and its customers
  Growth opportunities outside traditional gathering and processing
91
 
 
 
Key Value Drivers
  Execution on our Eagle Ford Shale strategy
  Strong producer activity in north Texas
  Expanded growth opportunities in the Woodford Shale and
 Mississippi Lime in Oklahoma
  Potential for future strategic acquisitions
  Shift to predominately fee-based contract mix
  Ample liquidity and access to capital to support growth initiatives
92
 
 
 
93
Appendix
 
 
 
Reconciliation of Non-GAAP Financial
Measures
94
Segment Gross Margin, Total Segment Gross Margin and Adjusted EBITDA
  We define segment gross margin as an operating segment's revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and
 NGLs we purchase and costs for transportation of our volumes. We view segment gross margin as an important performance measure of the core
 profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to
 more easily identify operational or other issues within a segment. With respect to our Texas and Oklahoma segments, our management analyzes
 segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin
 per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn
 and Fort Union.
  To measure the overall financial impact of our contract portfolio, we use total segment gross margin, which is the sum of our operating segments' gross
 margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined
 primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas
 processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas, oil and NGL
 prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities.
 The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii)
 amortization expense relating to the option component of our commodity derivative instruments and (iii) unrealized mark-to-market gain or loss on our
 commodity derivative instruments that have not been designated as cash flow hedges.
  We define EBITDA as net income (loss) plus interest expense, provision for income taxes and depreciation and amortization expense. Because a portion
 of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and
 Southern Dome), our management also calculates Adjusted EBITDA to reflect the depreciation and amortization expense embedded in equity in
 earnings (loss) from unconsolidated affiliates. Specifically, our management determines Adjusted EBITDA by adding to EBITDA (i) the amortization
 expense attributable to the difference between our carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii)
 the portion of each unconsolidated affiliate’s depreciation and amortization expense, which is proportional to our ownership interest in that
 unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs, which is proportional to our ownership
 interest in that unconsolidated affiliate.
  External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or Adjusted EBITDA, and our
 management uses Adjusted EBITDA, as a supplemental financial measure to assess:
 ■ The financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
 ■ The ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;
 ■ Our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to
 financing or capital structure; and
 ■ The viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.
  The following table presents a reconciliation of total segment gross margin to the GAAP financial measure of operating income and reconciliations of
 EBITDA and Adjusted EBITDA to the GAAP financial measure of net income (loss):
 
 
 
 
Reconciliation of Non-GAAP Financial
Measures
95
 
 
 
Reconciliation of Non-GAAP Financial
Measures
Consolidated EBITDA
  EBITDA is also a financial measure that, with negotiated pro forma adjustments relating to acquisitions completed during the period, is reported to our
 lenders as Consolidated EBITDA and is used to compute our financial covenants under our senior secured revolving credit facility.
  The following table presents a reconciliation of the non-GAAP financial measure of Consolidated EBITDA to the GAAP financial measure of net income
 (loss):
96
 
 
 
Reconciliation of Non-GAAP Financial
Measures
Total Distributable Cash Flow
  We define total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense
 relating to the option component of our risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and
 equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v)
 the subtraction of equity in earnings from unconsolidated affiliates and (vi) the addition of losses or subtraction of gains relating to other miscellaneous
 non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and our
 line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed to replace
 partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital
 expenditures that are incurred in maintaining existing system volumes and related cash flows.
  Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by us (prior to the
 establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders, and it also correlates
 with the metrics of our existing debt covenants. Using total distributable cash flow, management can quickly compute the coverage ratio of estimated
 cash flows to planned cash distributions. Total distributable cash flow is also an important non-GAAP financial measure for our unitholders because it
 serves as an indicator of our success in providing a cash return on investment — specifically, whether or not we are generating cash flow at a level that
 can sustain or support an increase in our quarterly distribution rates. Total distributable cash flow is also used by industry analysts with respect to
 publicly traded partnerships and limited liability companies because the market value of such entities’ equity securities is significantly influenced by the
 amount of cash they can distribute to unitholders.
 
97