Copano Energy, L.L.C. 8K Regulation FD Disclosure | CPNO 12 Oct 11

Exhibit 99.1

Deutsche Bank 19th Annual
Leveraged Finance Conference

October 11 - 13, 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.

Introduction to Copano

Independent midstream company founded in 1992

■ Producer focused

■ Entrepreneurial approach

■ Focus on long-term accretive growth

■ Publicly traded LLC

● No general partner or incentive distribution rights

● Tax benefits similar to MLPs, but with corporate governance of a C-corp

Service throughput volumes approximate 1,500,000 MMBtu/d of
natural gas(1)

Approximately 6,700 miles of active pipelines

10 natural gas processing plants with over 1.2 Bcf/d of combined
processing capacity

One NGL fractionation facility with total capacity of 22,000 Bbls/d

■ Expansion underway to increase total capacity to 44,000 Bbls/d

(1) Based on 2Q 2011 results. Includes unconsolidated affiliates.

Operating Segments

Operating segments

■ Texas

■ Oklahoma

■ Rocky Mountains

■ Copano currently has assets in five
active U.S. resource plays

● Eagle Ford Shale

● North Barnett Shale Combo

● Woodford Shale

● Mississippi Lime

● Powder River Basin Niobrara

Powder River
Basin Niobrara

Woodford
Shale

Mississippi
Lime

North Barnett
Shale Combo

Executing On Our Business Strategy

Eagle Ford Shale, North Barnett Shale Combo, Woodford
Shale and Mississippi Lime

Acquisition of the Harrah and Davenport plants

Organic Growth and
Bolt-on
Acquisitions

Maintaining Strong
Balance Sheet

Reduce Sensitivity
to Commodity
Prices

Flexibility in
Operations

Long-term, fee-based contracts - also reduce hedging
requirements

Access to multiple NGL markets

Ability to fractionate and produce y-grade product

Multiple plant residue alternatives

March 2010 equity offering

TPG Capital preferred equity investment

Senior notes refinancing

Extended maturity of revolver to 2016

Expand Midstream
Services Menu

Fractionation and NGL marketing services

Purity ethane and propane pipeline service

Y-grade service through the Liberty pipeline

Condensate gathering project in planning phase

Agenda

Eagle Ford Shale Growth Projects	Business Segment Outlook
Financing and Commodity Price Sensitivity	Conclusions

DK Pipeline and Extension

DK extension

■ 100% Copano-owned project

■ Key producer contracts with
Abraxas, GeoSouthern, Petrohawk,
Pioneer, Riley and others

■ Announced February 2011

● 58 miles of 24” pipe

● Construction approximately 70%
complete

■ Loops Kinder Morgan’s Index 50
pipeline, effectively boosting
capacity for Eagle Ford Shale
volumes to Houston Central complex

■ Extension to Houston Central
complex will increase DK pipeline
capacity to 350,000 MMBtu/d from
225,000 MMBtu/d

■ Estimated capital investment of
$100 million

Southern Eagle Ford Shale

Eagle Ford Gathering (EFG)

■ 50/50 JV with Kinder Morgan

EFG Mainline

■ Copano constructed and operates

■ 117 miles of 30” and 24” pipe -
substantially complete

■ 30” pipeline now accepting
interruptible gas with full service
expected November 2011

■ Nominal capacity of 600,000
MMBtu/d - expandable with
compression

■ Long-term, fee-based contracts with
volume commitments for nearly
100% of nominal capacity

■ Estimated capital investment of
$87.5 million

EFG Crossover

Allows for full utilization of EFG
Mainline pipeline

66 miles of 24” and 20” pipe
connecting Kinder Morgan’s
Index 50 and Tejas 30”
pipelines to Formosa

7 miles of 20” pipe connecting
Kinder Morgan’s Tejas 30”
pipeline to Williams Partners’
Markham plant

In October 2011, began
deliveries to Markham plant

EFG Crossover (cont’d)

Long-term contracts with
Formosa and Williams Partners

■ Formosa - will provide 175 MMcf/d
of processing, fractionation and
product sales

■ Williams Partners’ Markham - 100
MMcf/d processing and associated
with fractionation available today,
with an option to increase to 200
MMcf/d

● Copano to construct wholly
owned 8-mile, 6” NGL pipeline
from Markham plant to Liberty
NGL pipeline estimated capital
investment of $5.5 million

Houston Central Complex

Fractionation expansion

■ Fractionation expansion from
22,000 Bbls/d to 44,000
Bbls/d

● All ethane and propane
expected to move to Dow
through Copano purity
pipelines

■ Estimated capital investment
of $66 million

● Includes fractionation
facilities and related plant
upgrades and product
pipeline expansions

Liberty NGL Pipeline

■ Total capacity of 75,000 Bbls/d

■ Copano constructed and operates
through 50/50 JV with Energy Transfer

■ Pipeline placed into full service in
September 2011

Long-term fractionation and product
sales agreement with Formosa on
favorable terms

■ Initial access to 7,000 Bbls/d

■ Upon completion of Formosa’s
fractionation expansion 1Q 2013, will
have up to 37,500 Bbls/d of firm capacity
for a 15-year term

Houston Central NGL Infrastructure

Access to Dow and Formosa

■ Among the largest petrochemical users of NGLs in the U.S.

■ Long-term contracts with both Dow and Formosa

Summary of Eagle Ford Shale
Infrastructure

Total capital investment of over $500 million

In excess of 1 Bcf/d of pipeline and processing capacity

Greater than 100,000 Bbls/d of fractionation capacity

Access to multiple markets for residue gas and NGLs

Growth Opportunities - Eagle Ford Shale

Potential extension of 100%
Copano-owned DK pipeline to
Fashing / Live Oak system

■ Continues loop of Kinder
Morgan’s Index 50 pipeline
through the Eagle Ford Shale
condensate window

● 34 miles of 24” pipe

● Allows for gathering of
approximately 50,000 MMBtu/d
from additional Eagle Ford
Shale acreage

■ Ties additional existing Copano
gathering systems directly to
Houston Central complex

■ Potential connectivity to the EFG
JV Crossover line for DK pipeline
and Fashing / Live Oak volumes

Growth Opportunities - Eagle Ford Shale

Condensate initiative

■ 100,000 Bbls/d capacity pipeline

■ Fee-based revenue

■ Working to complete definitive JV
agreements and secure anchor
shipper by November 2011

■ Convert existing 14” Copano
Goebel line to condensate service

■ Tie into existing markets, storage
and loading docks in Corpus Christi

■ Utilize dual-line rights of way in the
DK corridor to lay condensate
gathering system

■ Proposed pipeline from Three
Rivers to Corpus Christi would
begin service in mid-2012;
remaining assets would begin 4Q
2012

Business Segment Outlook

Eagle Ford Shale Growth Projects	Business Segment Outlook
Financing and Commodity Price Sensitivity	Conclusions

Texas Recent Developments

Saint Jo system - North Barnett Shale Combo

■ Gathering, treating and processing

■ Plant fully committed under long-term, fee-based contracts

■ Plant running at or near capacity of 100 MMcf/d

Eagle Ford Shale

■ Copano’s total Eagle Ford Shale volumes have been averaging approximately
250,000 MMBtu/d

■ EFG 30” pipeline currently accepting interruptible gas (until Freer liquids
handling facility is operational in November), and EFG Crossover is delivering
gas to Williams Partners’ Markham plant

Lake Charles plant

■ Executed agreements for both natural gas receipt logistics and fractionation
and product sales

● Equipment has been procured and installed with expected in-service date in
mid-October

■ Minimal capital investment - approximately $5 million

Texas Outlook

Saint Jo system

■ Copano’s largest producer has 11 rigs running in the area and expects to run
11 - 12 rigs for the remainder of the year

● On track to connect approximately 150 wells in 2011

■ Leasing activity continues

■ Evaluating opportunity to expand Saint Jo plant by 50,000 Mcf/d - 100,000
Mcf/d

Eagle Ford Shale

■ Over 190 rigs currently running in the Eagle Ford Shale

■ As 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

Expect lower segment gross margin in 3Q 2011 compared to 2Q
2011 due primarily to conditioning (reduced liquids recovery) at
Houston Central complex during September as a result of Formosa’s
42-day planned turnaround

Oklahoma Recent Developments

Acquisition of Harrah plant from
Enogex (April 2011)

■ Contributed $1.5 million in gross margin
in 2Q 2011

Strong drilling activity in the
Woodford Shale around the Cyclone
Mountain system

■ 2Q 2011 volumes increased an average
of 4,500 Mcf/d compared to 1Q 2011

■ Two additional wells connected in late
July 2011 with combined rate of 14,000
Mcf/d

Recently completed construction of
Featherston treating and
compression station to handle
additional volumes

■ Capacity of 30,000 Mcf/d

■ Further expansion in 2012 anticipated

Oklahoma Outlook

Rich gas (primarily Hunton dewatering and Mississippi Lime)

■ Drilling activity has increased in 3Q 2011 compared to 2Q 2011

■ 3 rigs running in the Hunton, 4 rigs in the Mississippi Lime and 13 rigs in other
rich gas areas

■ Attractive processing upgrade and low geologic risk

Lean gas (primarily Woodford Shale)

■ Drilling activity remains steady in 3Q 2011 compared to 2Q 2011

■ 3 rigs running

Expect Oklahoma gross margin to be slightly higher in 3Q 2011
compared to 2Q 2011

Rocky Mountains Outlook

Drilling and dewatering will be driven by commodity prices and
producer economics

3Q 2011 volumes for Bighorn expected to be slightly lower vs. 2Q
2011

3Q 2011 volumes for Fort Union expected to be higher vs. 2Q 2011
due to the Bison pipeline rupture

Second half 2011 Adjusted EBITDA expected to be slightly lower
vs. first half 2011

Recently approved project to connect 145 wells that have been
drilled, but not yet dewatered on the Bighorn system

■ Volumes to flow once dewatering process is complete (12 - 18 months)

Financing and Commodity Price
Sensitivity

Eagle Ford Shale Growth Projects	Business Segment Outlook
Financing and Commodity Price Sensitivity	Conclusions

Liquidity and Capitalization

At June 30, 2011:

■ $62 million cash

■ $700 million revolving credit facility

● Closed in June 2011 - added flexibility to existing financial covenants

● Approximately $360 million available

● Matures June 2016

■ $609.5 million senior notes

● $360.0 million 7.125% senior notes due 2021

● $249.5 million 7.75% senior notes due 2018

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

Contract Mix as a % of Gross Margin
	1Q 2010	2Q 2010	3Q 2010	4Q 2010	1Q 2011	2Q 2011
Fee-based	27%	33%	37%	38%	41%	41%
Percentage-of- proceeds	39%	31%	30%	32%	32%	33%
Keep- whole/Other	36%	33%	29%	34%	39%	40%
Net hedging	-2%	3%	4%	-4%	-12%	-14%

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 as contract mix changes over time

2011 well hedged

■ Between 70% and 90% of ethane, propane, butane, natural gasoline and
condensate exposure is hedged

2012 hedged near policy limits for all products except ethane

■ Approximately 80% of propane, butane, natural gasoline and condensate
exposure hedged

■ Approximately 40% of ethane exposure hedged

● Recently added 500 Bbls/d of put options with a strike price of $0.59/gal

2013 hedging positions continue to be added

■ Between 40% and 70% of butane, natural gasoline and condensate exposure
hedged

■ Approximately 40% of propane exposure hedged

■ No ethane hedges for 2013

Conclusions

Eagle Ford Shale Growth Projects	Business Segment Outlook
Financing and Commodity Price Sensitivity	Conclusions

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

Experienced
Operator /

Seasoned Team

Strong Balance
Sheet with
Access to
Liquidity

Strategic and
Diverse Asset
Base

Significant
Organic Growth

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

Approximately $440 million in 2011 growth projects (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

Cash flow growth 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 on a combined basis

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

(1) Includes Copano’s net share for unconsolidated affiliates.

Appendix

Oklahoma Assets

OKLAHOMA

South Texas Assets

TEXAS

North Texas Assets

TEXAS

Rocky Mountains Assets

WYOMING

Solid Core Business Growth

From 1Q 2009 to 2Q 2011, Texas and Oklahoma operating
segment gross margins has increased approximately 114%

Commodity-Related Margin Sensitivities

Matrix reflects 2Q 2011 wellhead and plant inlet volumes, adjusted
using Copano’s 2011 planning model

(1) Consists of Texas and Oklahoma Segment gross margins.

Oklahoma Net Commodity Exposure

Note: See explanation of processing modes in this Appendix. Values reflect rounding.

(1) Source: Copano Energy internal financial planning models.

(2) Ethane rejection at Paden plant is limited by nitrogen rejection facilities.

(3) Reflects impact of producer delivery point allocations, offset by field condensate collection and stabilization.

Oklahoma Commodity Price Sensitivities

Oklahoma segment gross margins excluding hedge settlements

■ Matrix reflects 2Q 2011 volumes, adjusted using Copano’s 2011 planning
model

Note: Please see this Appendix for definitions of processing modes and additional details.

Texas Net Commodity Exposure

Note: See explanation of processing modes in this Appendix.

(1) Source: Copano Energy internal financial planning models. Based on 1Q 2011 daily wellhead/plant inlet volumes.

(2) Fractionation at Houston Central complex permits significant reductions in ethane recoveries in ethane rejection mode. To optimize profitability, plant
operations can also be adjusted to partial recovery mode.

(3) At the Houston Central complex, pentanes+ may be sold as condensate.

Texas Commodity Price Sensitivities

Texas segment gross margins excluding hedge settlements

■ Matrix reflects 2Q 2011 volumes and operating conditions, adjusted using
Copano’s 2011 planning model

Note: Please see this Appendix for definitions of processing modes and additional details.

Rocky Mountains Sensitivities

2Q 2011 Adjusted EBITDA volume sensitivity (positive or negative
impact)

■ Bighorn: 10,000 MMBtu/d = $245,000(1)

■ Fort Union: 10,000 MMBtu/d = immaterial impact until physical volumes
exceed long-term contractual volume commitments

● 2Q 2011 pipeline throughput: 391,626 MMBtu/d

● 2Q 2011 revenue based on 719,520 MMBtu/d of volume commitments

Note: See this Appendix for reconciliation of Adjusted EBITDA. Values reflect rounding.

(1) Impact on Adjusted EBITDA based on Copano’s interest in the unconsolidated affiliate.

Hedging Impact of Commodity Price
Sensitivities

Processing Modes

Full Recovery
	Texas and Oklahoma - If the value of recovered NGLs exceeds the fuel and gas shrinkage costs of recovering NGLs
Ethane Rejection
	Texas and Oklahoma - If the value of ethane is less than the fuel and shrinkage costs to recover ethane (in Oklahoma, ethane rejection at Paden plant is limited by nitrogen rejection facilities)

Reconciliation of Non-GAAP Financial
Measures

Adjusted EBITDA

Commencing with the second quarter of 2011, we revised our calculation of adjusted EBITDA to more closely resemble that of many of our peers in terms of measuring our
ability to generate cash. Our adjusted EBITDA (as revised) equals:

■ net income (loss);

■ plus interest and other financing costs, provision for income taxes, depreciation, amortization and impairment expense, non-cash amortization expense associated with
our commodity derivative instruments, distributions from unconsolidated affiliates, loss on refinancing of unsecured debt and equity-based compensation expense;

■ minus equity in earnings (loss) from unconsolidated affiliates and unrealized gains (losses) from commodity risk management activities; and

■ plus or minus other miscellaneous non-cash amounts affecting net income (loss) for the period.

In calculating adjusted EBITDA as revised, we no longer add to EBITDA (earnings before interest taxes depreciation and amortization our share of the depreciation,
amortization and impairment expense and interest and other financing costs embedded in our equity in earnings (loss) from unconsolidated affiliates; instead we now add to
EBITDA (i) our impairment expense, and other non-cash amounts affecting net income (loss) for the period, (ii) non-cash amortization expense associated with our
commodity derivative instruments, (iii) loss on refinancing of unsecured debt and (iv) distributions from unconsolidated affiliates.

We believe that our revised calculation of adjusted EBITDA is a more effective tool for our management in evaluating our operating performance for several reasons.
Although our historical method for calculating adjusted EBITDA was useful in assessing the performance of our assets (including our unconsolidated affiliates) without regard
to financing methods, capital structure or historical cost basis, the prior calculation was not as useful in evaluating the core performance of our assets and their ability to
generate cash because adjustments for a number of non-cash expenses and other non-cash and non-operating items were not reflected in the calculation and the impact of
cash distributions from our unconsolidated affiliates was likewise not reflected. We believe that the revised calculation of adjusted EBITDA is more consistent with the method
and presentation used by many of our peers and will allow management and analysts to better evaluate our performance relative to our peer companies. Also, we believe
that the revised calculation more effectively represents what lenders and debt holders, as well as industry analysts and many of our unitholders, have indicated is useful in
assessing our core performance and outlook and comparing us to other companies in our industry.

Copano Energy, L.L.C. (CPNO) 8-KRegulation FD Disclosure