Copano Energy, L.L.C. - FORM 8-K - EX-99.2 - 2010 MLP INVESTOR CONFERENCE PRESENTATION

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8-K - COPANO ENERGY, L.L.C. FORM 8-K - Copano Energy, L.L.C.	form8-k.htm
EX-99.1 - COPANO ENERGY, L.L.C. PRESS RELEASE - Copano Energy, L.L.C.	ex99-2.htm

NAPTP Annual MLP Investor
Conference

May 12, 2010

NASDAQ: CPNO

Disclaimer

Statements made by representatives of Copano Energy, L.L.C. (“Copano”) during this presentation will
include “forward-looking statements,” as defined in the federal securities laws. All statements that
address activities, events or developments that Copano believes will or may occur in the future are
forward-looking statements. Underlying these statements are assumptions made by Copano’s
management based on their experience and perceptions of historical trends, current conditions,
expected future developments and other factors management believes are appropriate under the
circumstances.

Whether future results and developments will conform to Copano’s expectations is subject to a number
of risks and uncertainties, many of which are beyond Copano’s control. If one or more of these risks or
uncertainties materializes, or if underlying assumptions prove incorrect, then Copano’s actual results
may differ materially from those implied or expressed by forward-looking statements made during this
presentation. These risks and uncertainties include the volatility of prices and market demand for
natural gas and natural gas liquids; Copano’s ability to complete any pending acquisitions and integrate
any acquired assets or operations; Copano’s ability to continue to obtain new sources of natural gas
supply; the ability of key producers to continue to drill and successfully complete and attach new
natural gas supplies; Copano’s ability to retain key customers; the availability of local, intrastate and
interstate transportation systems and other facilities to transport natural gas and natural gas liquids;
Copano’s ability to access sources of liquidity when needed and to obtain additional financing, if
necessary, on acceptable terms; the effectiveness of Copano’s hedging program; unanticipated
environmental or other liability; 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
the Risk Factors sections of Copano’s annual and quarterly 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

■ Best in class service to customers

■ Entrepreneurial approach

■ Focus on long-term accretive growth

Provides midstream services in multiple producing areas through
three operating segments

■ Texas

● South Texas conventional and Eagle Ford Shale

● North Texas Barnett Shale Combo play

■ Central and Eastern Oklahoma

● Conventional, Hunton De-Watering play and Woodford Shale

■ Rocky Mountains

● Powder River Basin

Key Metrics

Service throughput volumes approximate 1.8 Bcf/d of natural gas(1)

Over 6,700 miles of active pipelines

8 natural gas processing plants with over 1.1 Bcf/d of combined
processing capacity

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

Equity market cap: $1.6 billion(2)

Enterprise value: $2.2 billion(2)

Based on 1Q 2010 results. Includes unconsolidated affiliates.

As of May 7, 2010.

Copano’s LLC Structure

Growth Strategy

Goal: to become a diversified midstream company with scale and
stability of cash flows, above-average returns on invested capital
and “investment-grade quality distributions”

Key tenets of growth strategy:

■ Execute on organic growth opportunities around existing assets

■ Explore opportunities beyond traditional gathering and processing

● Be more proactive in seeking assets and opportunities

■ Reduce sensitivity of cash flows to commodity price fluctuations

● Hedging program

● Contracts - increase fee-for-service component

Agenda

2010 Regional Outlook	Commodity Prices and Margin Sensitivities
Financing and Commodity Risk Management	Conclusions

2010 Outlook

Texas

■ North Texas: Significant drilling and development activity in the Barnett Shale
Combo play

■ South Texas: Ramp up of Eagle Ford Shale directed drilling

Oklahoma

■ Moderate drilling activity behind both the Hunton De-Watering and Woodford
Shale plays

Rocky Mountains

■ Minimal new drilling; flat volumes

Texas Outlook

North Texas

■ 9 rigs running in the area with
as many as 4 more anticipated
later this year

● Leasing activity also
continues

■ Crude oil play with associated
gas requiring a full slate of
midstream services

■ Based on producer drilling
schedule, expect steady
increase in plant inlet volumes
in 2010

● Current spot volumes of
approximately 38 MMcf/d vs.
1Q 2010 average volumes of
21 MMcf/d

Texas Outlook

South Texas

■ Fractionation start-up at Houston Central complete

■ To date we have connected 6 Eagle Ford Shale wells with a combined IP rate
of 40 MMcf/d with significant associated condensate

■ Finalizing joint venture agreements with Kinder Morgan for the western
portion of the Eagle Ford Shale

■ Expect further Eagle Ford Shale volume increases in 2Q 2010

Texas Recent Developments

North Texas

■ Recently executed key producer
contract

● Long-term gathering, treating and
processing agreement

● Fee-for-service contract

● Highly rated producer

■ Additional 50 MMcf/d of compression
expected in service early 4Q 2010,
bringing total plant capacity to 100
MMcf/d

■ Approximately $30 million in expansion
capex for 2010 (compression and
pipelines)

■ $30 - $35 million in fee-based cash flow
expected by year-end 2010 on an
annualized basis

DeWitt-Karnes Pipeline

Recently announced DeWitt-
Karnes pipeline

■ Targets rich Eagle Ford Shale gas

■ 38 miles of 24” pipe - expected to
be in service by August 1, 2010

■ Anticipated 2010 capex -
approximately $45 million

Conducting preliminary
engineering work to relocate
200 MMcf/d Lake Charles
plant to Houston Central

Texas Fractionation Facility

Responding to NGL transportation and fractionation constraints
along the Texas Gulf Coast, Copano started its fractionator at
Houston Central

Utilizing Houston Central’s fractionation unit and extensive
tailgate NGL pipelines, Copano began to deliver purity products
to market in April 2010

■ Total capacity of 22,000 Bbls/d

■ Approximate cost of $17 million

■ Estimated fee-based cash flow between $8 and $10 million on an
annualized basis at current throughput volumes

Oklahoma Outlook

Rich gas (primarily Hunton De-Watering play)

■ Drilling activity remains steady

■ 2 rigs currently running in the Hunton and 7 rigs in other rich gas areas

■ Attractive processing upgrade and low geologic risk

■ 2Q 2010 volumes expected to be flat to slightly up vs. 1Q 2010

■ Burbank processing plant in service 2Q 2010 (10 MMcf/d capacity)

Lean gas (primarily Woodford Shale and coalbed methane)

■ Drilling activity in the Woodford Shale has recently increased

■ 5 rigs currently running

■ 2Q 2010 volumes expected to be slightly up from 1Q 2010

Oklahoma Rich Gas vs. Lean Gas

Prices as of 5/7/10

Full value prior to deduction of Copano’s margin. Excludes value of condensate and crude oil recovered by the producer at the wellhead.

Implied NGL prices are based on a six-year historical regression analysis.

Assumes 9 GPM gas with a Btu factor of 1.375 processed at Copano’s cryogenic plant, and field fuel of 6.25%.

Assumes unprocessed gas with a Btu factor of 1.0 and field fuel of 6%.

Rocky Mountains Outlook

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

2Q 2010 volumes expected to be slightly lower to flat vs. 1Q 2010

For Bighorn, 130 previously drilled wells can be connected with
minimal capital expenditures

■ An additional 70 drilled wells can be connected with moderate capital
expenditures

2010 Adjusted EBTIDA expected to be flat vs. 2009

■ Forward pricing curve indicates drilling and dewatering activity should resume
this year and if this occurs, 2014 Adjusted EBITDA could double from current
levels

Commodity Prices and Margin Sensitivities

2010 Regional Outlook	Commodity Prices and Margin Sensitivities
Financing and Commodity Risk Management	Conclusions

Historical Commodity Prices

May-09 NGL prices are month-to-date through May 6, 2010.

NGL prices for Jan-09 through Mar-10 are calculated based on the weighted-average product mix for the period indicated. NGL prices for Apr-10 through
May-10 are calculated based on the first quarter 2010 product mix.

Forward Commodity Prices

Note: Forward prices as of May 6, 2010

Combined Commodity-Sensitive Segment
Margins and Hedging Settlements

Financing and Commodity Risk Management

2010 Regional Outlook	Commodity Prices and Margin Sensitivities
Financing and Commodity Risk Management	Conclusions

2010 Expansion Capex

Copano has approximately $130 million(1) in approved expansion
capital projects for 2010. Major areas of focus include:

■ Eagle Ford Shale and Houston Central processing plant in south Texas

● DeWitt-Karnes pipeline

■ Saint Jo processing plant and pipelines in north Texas

■ Additional pipeline and processing capacity in Oklahoma

■ Expect capital to be invested at a multiple of approximately 5x

Financing to be consistent with Copano’s historical policy - balance
of debt and equity

Includes Copano’s net share for unconsolidated affiliates.

Recent Equity Offering

In March 2010 Copano sold approximately 7.45 million common
units in a public offering

■ Approximately $164 million in net proceeds (including greenshoe)

■ Proceeds used to reduce revolver borrowings, which ultimately will fund
expansion capex

■ Demonstrated commitment to raising capital and maintaining liquidity

Enhances liquidity available to fund expansion capex and balance
sheet

■ At March 31, 2010, total liquidity of approximately $301 million

Hedging Strategy

Option-based, product-specific

2010 price exposed volumes are well hedged

■ Between 70% and 80% of propane, butane, natural gasoline and condensate
price exposure is hedged

■ Approximately 40% of ethane price exposure is hedged

■ Expect $32 - $34 million of non-cash amortization expense in 2010 related to
option component of hedge portfolio

So far in 2010:

■ Added ethane puts for 2011 (net cost of approximately $0.7 million)

■ Added ethane, propane, isobutane, normal butane and WTI puts for 2012 (net
cost of approximately $10.1 million)

2010 focus - adding to 2012 hedging positions

Conclusions

2010 Regional Outlook	Commodity Prices and Margin Sensitivities
Financing and Commodity Risk Management	Conclusions

Conclusions

Growth projects recently completed are expected to contribute to
increased total distributable cash flow in 2010

■ Volumes at Saint Jo plant increasing

■ Start-up of fractionator at Houston Central plant

■ Burbank plant in-service

■ Portions of DeWitt-Karnes header in-service

Significant funnel of growth opportunities

■ Expansion of Saint Jo plant to 100 MMcf/d anticipated by early 4Q 2010

■ Completion of DeWitt Karnes Header expected by mid-3Q 2010

■ Finalizing Kinder Morgan joint venture in western Eagle Ford Shale

■ Other processing plant expansions, fractionation expansion and additional
pipelines

Ample liquidity and access to capital to support growth initiatives

Appendix

Oklahoma Assets

OKLAHOMA

South Texas Assets

TEXAS

North Texas Assets

TEXAS

Rocky Mountains Assets

WYOMING

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)
Conditioning Mode
	Texas - If the value of recovered NGLs is less than the fuel and gas shrinkage cost of recovering NGLs (available at Houston Central plant and at Saint Jo plant in North Texas)

Commodity-Related Margin Sensitivities

Matrix reflects 1Q 2010 wellhead and plant inlet volumes, adjusted
using Copano’s 2010 planning model

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

Consists of Texas and Oklahoma Segment gross margins.

Combined Commodity-Sensitive Segment
Margins and Hedging Settlements

Note: Weighted average NGL prices are based on Copano product mix for period indicated.

Does not include non-cash expenses included in Corporate and Other for purposes of calculating Total Segment Gross Margin. See Appendix for
reconciliation of Total Segment Gross Margin.

Reflects the average of April and May (as of May 6, 2010) prices.

Oklahoma Contract Mix

Source: Copano Energy internal financial planning models for consolidated subsidiaries.

Excludes 14,130 MMBtu/d service throughput for Southern Dome, a majority-owned affiliate.

Oklahoma Net Commodity Exposure

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

Source: Copano Energy internal financial planning models for consolidated subsidiaries.

Ethane rejection at Paden plant is limited by nitrogen rejection facilities.

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 1Q 2010 volumes, adjusted using Copano’s 2010 planning
model

Texas Contract Mix

Source: Copano Energy internal financial planning models for consolidated subsidiaries.

Excludes 66,764 MMBtu/d service throughput for Webb Duval, a majority-owned affiliate.

Texas Net Commodity Exposure

Note: See explanation of processing modes in this Appendix.

Source: Copano Energy internal financial planning models for consolidated subsidiaries. Based on 1Q 201 daily wellhead/plant inlet volumes.

Fractionation at Houston Central processing plant permits significant reductions in ethane recoveries in ethane rejection mode and full ethane rejection in
conditioning mode. To optimize profitability, plant operations can also be adjusted to partial recovery mode.

At the Houston Central processing plant, pentanes+ may be sold as condensate.

Texas Commodity Price Sensitivities

Texas segment gross margins excluding hedge settlements

■ Matrix reflects 1Q 2010 volumes and operating conditions, adjusted using
Copano’s 2010 planning model

Rocky Mountains Sensitivities

1Q 2010 Adjusted EBITDA volume sensitivity (positive or negative
impact)

■ Bighorn: 10,000 MMBtu/d = $244,000(1)

■ Fort Union: 10,000 MMBtu/d = $70,000(1)

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

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

Hedging Impact of Commodity Price
Sensitivities

Liquidity and Debt Facilities

At March 31, 2010:

■ Cash: Approximately $54 million

■ $550 million revolving credit facility

● Approximately $247 million available (limited by debt covenants)

● Remaining term: approximately 2.6 years

● LIBOR + 200 bps

■ $582 million senior notes

● $332,665,000 8 ⅛% due 2016

● $249,525,000 7 ¾% due 2018

● Weighted average rate: 7.96%

● Weighted average maturity: 6.9 years

Key Debt Terms and Covenants

Senior Secured Revolving Credit Facility

■ $550 million facility with $100 million accordion

■ Maintenance tests:

● 5x total debt to defined EBITDA(1) limitation

Ø 3.7x at March 31, 2010

● Minimum required interest coverage 2.5x defined EBITDA

Ø 3.5x at March 31, 2010

● Defined EBITDA adds back hedge amortization and other non-cash
expenses

■ Following an acquisition, Copano may increase total debt to defined EBITDA
limitation to 5.5x for three quarters

Senior Notes

■ Incurrence tests:

● Minimum defined EBITDA to interest test of 2.00x for debt incurrence

● Minimum defined EBITDA to interest test of 1.75x for restricted payments

● Defined EBITDA is similar to that for credit facility

See this Appendix for reconciliation of defined EBITDA, which is referred to in our credit facility as “Consolidated EBITDA.”

Distribution Outlook

Reconciliation of Non-GAAP Financial
Measures

Segment Gross Margin and Total Segment Gross Margin

We define segment gross margin, with respect to a Copano operating segment, as segment revenue less cost of sales. Cost of sales includes the
following: cost of natural gas and NGLs purchased from third parties, cost of natural gas and NGLs purchased from affiliates, cost of crude oil purchased
from third parties, costs paid to third parties to transport volumes and costs paid to affiliates to transport volumes. Total segment gross margin is the
sum of the operating segment gross margins and the results of Copano’s risk management activities that are included in Corporate and other. We view
total segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows Copano’s
senior management to compare volume and price performance of the segments and to more easily identify operational or other issues within a
segment. The GAAP measure most directly comparable to total segment gross margin is operating income.

Reconciliation of Non-GAAP Financial
Measures

Adjusted EBITDA

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.

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):

Definitions 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.

Copano Energy, L.L.C. - FORM 8-K - EX-99.2 - 2010 MLP INVESTOR CONFERENCE PRESENTATION - May 12, 2010

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