Copano Energy, L.L.C. - FORM 8-K - EX-1 - MARCH INVESTOR PRESENTATION

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8-K - COPANO ENERGY, L.L.C. FORM 8-K - Copano Energy, L.L.C.	form8-k.htm

Copano Energy

March Investor Presentation

NASDAQ: CPNO

March 8, 2010

Copano Energy

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.

Copano Energy

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

Copano Energy

Key Metrics

• Service throughput volumes approximate 2 Bcf/d of natural gas(1)

• Approximately 6,700 miles of active pipelines

• 7 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
(in-service expected end of Q1 2010)

• Equity market cap: $1.5 billion(2)

• Enterprise value: $2.3 billion(2)

(1) Based on 4Q 2009 results. Includes unconsolidated affiliates.

(2) As of March 4, 2010. Reflects March 2010 equity offering.

Copano Energy

Copano’s LLC Structure

Characteristic	Typical MLP	Copano Energy	Typical Corporation
Non-Taxable Entity
Tax Shield on Distributions
Tax Reporting
General Partner
Incentive Distribution Rights
Voting Rights

Schedule K-1

Form 1099

Copano Energy

Agenda

2010 Regional
Outlook

Commodity
Prices and
Margin
Sensitivities

Financing and
Commodity Risk
Management

Distribution
Outlook and
Conclusions

Copano Energy

• Overall focus was maintaining liquidity and watching costs - enabled
Copano to maintain distributions

– 2009 total distributable cash flow coverage averaged 107% - all
quarters in excess of 100% coverage

• Copano’s hedging strategy supported 2009 cash flow

– Option-focused and product-specific

– Strategy protects downside, without the loss of upside

• Volumes - 2009 vs. 2008

– 2009 total service throughput volumes(1) declined 4%

• Most significant declines seen in lower-margin third-party volumes in Texas
and Woodford Shale gas in Oklahoma

– NGL volumes(1) increased by 9%

• Volumes stabilized as NGL pricing strengthened in 2009 relative to lows in
late 2008/early 2009

2009 Review

(1) Includes unconsolidated affiliates.

Copano Energy

• 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

2010 Outlook

Copano Energy

North Texas Outlook

• 9 rigs running in the
area with as many as 3
more anticipated later
this year

• Drilling economics are
driven by associated
crude oil production

• Production from this
area requires a full slate
of midstream services

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

Copano Energy

North Texas Recent Developments

• Recently executed key producer
contract

– Long-term gathering, treating and
processing agreement

– Fee-for-service contract

• No incremental hedging costs

– Highly rated producer

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

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

• $25 - $30 million in fee-based cash flow
expected by year-end 2010 on an
annualized basis

Copano Energy

South Texas Outlook

• In 4Q 2009, announced plans for a joint venture with Kinder
Morgan to provide gathering, transportation and processing
services to gas producers in the Eagle Ford Shale. Producer
decisions to commit have been delayed by:

– Gas quality variability

– Desire to seek capital partners (in case of small to mid-sized
producers)

• Connected a third Eagle Ford Shale well in 1Q 2010, which IP’d
at 17 MMcf/d

• 1Q 2010 pipeline throughput volumes are expected to be higher
compared to 4Q 2009 due to recently connected Eagle Ford wells
and other drilling behind legacy systems

Copano Energy

DeWitt-Karnes Pipeline

• Recently announced DeWitt-Karnes pipeline

– Targets rich Eagle Ford Shale gas

– 38 miles of 24” pipe - expected to be in service July 2010

– Anticipated 2010 capex - approximately $45 million

• Complements Houston Central fractionation project

Copano Energy

Texas Fractionation Strategy

• Responding to NGL transportation
and fractionation constraints along
the Texas Gulf Coast, Copano will
re-start its fractionator at Houston
Central

• Utilizing Houston Central’s
fractionation unit and extensive
tailgate NGL pipelines, Copano
plans to produce purity products
by April 1, 2010

– Total capacity of 22,000 Bbls/d

– Approximate cost of $15 million

– Estimated fee-based cash flow
between $8 and $10 million on an
annualized basis

Copano Energy

• Rich gas (primarily Hunton De-Watering play)

– Drilling activity remains steady

– 2 rigs currently running in the Hunton and 8 rigs in other rich
gas areas

– Attractive processing upgrade and low geologic risk

– 1Q 2010 volumes expected to be flat to slightly up vs. 4Q 2009

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

• Lean gas (primarily Woodford Shale and coalbed methane)

– Drilling activity slightly increasing due to current commodity
prices and long-term price outlook

– 8 rigs currently running

– 1Q 2010 volumes expected to be slightly up from 4Q 2009

Oklahoma Outlook

Copano Energy

Oklahoma Rich Gas vs. Lean Gas

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

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

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

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

Prices as of 3/2/10

Copano Energy

Rocky Mountains Outlook

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

• 1Q 2010 volumes expected to be flat vs. 4Q 2009

• 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

Copano Energy

Commodity Prices and Margin
Sensitivities

Commodity
Prices and
Margin
Sensitivities

Distribution
Outlook and
Conclusions

Financing and
Commodity Risk
Management

2010 Regional
Outlook

Copano Energy

Historical Commodity Prices

(1) NGL prices are month-to-date through March 2, 2010.

(2) NGL prices for Jan-09 through Dec-09 are calculated based on the weighted-average product mix for the period
indicated. NGL prices for Jan-10 through Mar-10 are calculated based on the fourth quarter 2009 product mix.

(1)

(2)

Copano Energy

Note: Forward prices as of March 2, 2010

Forward Commodity Prices

Copano Energy

Combined Commodity-Sensitive Segment Margins
and Hedging Settlements

• Copano’s hedge portfolio supports cash flow stability based on
combined segment gross margins and cash hedging settlements

Copano Energy

Commodity-Related Margin
Sensitivities

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

• Matrix reflects 4Q 2009 wellhead and plant inlet volumes,
adjusted using Copano’s 2009 planning model

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

Copano Energy

Combined Commodity-Sensitive Segment Margins
and Hedging Settlements

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

(1) 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.

(2) Reflects prices as of March 2, 2010.

Copano Energy

Financing and Commodity Risk
Management

Financing and
Commodity Risk
Management

Distribution
Outlook and
Conclusions

Commodity
Prices and
Margin
Sensitivities

2010 Regional
Outlook

Copano Energy

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 - recently upsized project from $20 million
to $45 million

– 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

(1) Includes Copano’s net share for unconsolidated affiliates. Does not include future potential acquisitions.

Copano Energy

Recent Equity Offering

• On March 3, 2010 Copano sold 6.475 million common units
in a public offering

– Approximately $143 million in net proceeds (excluding
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 December 31, 2009, as adjusted for offering

• Total liquidity of approximately $309 million

• Total debt to defined EBTIDA(1) reduced to 3.7x (compared to
4.4x prior to offering)

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

Copano Energy

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

• January 2010 - announced addition of ethane and propane
hedges for 2012 (net cost of approximately $7.3 million)

– 2010 focus - adding to 2012 hedging positions

Copano Energy

Distribution Outlook and
Conclusions

Distribution
Outlook and
Conclusions

Financing and
Commodity Risk
Management

Commodity
Prices and
Margin
Sensitivities

2010 Regional
Outlook

Copano Energy

Distribution Track Record

• On January 13, 2010, Copano announced a cash distribution for
the fourth quarter of 2009 of $0.575 per common unit

(3)(4)

(1) All pre-1Q 2007 distributions are adjusted to reflect Copano’s 3/30/07 two-for-one unit split.

(2) Assumes generic MLP splits with 10%, 25% & 50% increases in distributable cash flow to LP units resulting in
incremental 13%, 23% and 48% increases in the percentage of total distributable cash flow applicable to the GP.

(3) Actual $0.10 distribution per unit was for the period from November 15, 2004 through December 31, 2004.

(4) 4Q 2004 annualized.

Copano Energy

Distribution Outlook

Copano Energy

• 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

Growth Strategy

Copano Energy

Appendix

Copano Energy

Oklahoma Assets

Appendix

Copano Energy

South Texas Assets

Appendix

Copano Energy

North Texas Assets

Appendix

Copano Energy

Rocky Mountains Assets

Appendix

Copano Energy

Processing Modes

• Full Recovery

• Ethane Rejection

• Conditioning Mode

→ Texas and Oklahoma - If the value of
recovered NGLs exceeds the fuel and gas
shrinkage costs of recovering NGLs

→ 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)

→ 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)

Appendix

Copano Energy

Oklahoma Contract Mix

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

(2) Excludes 12,639 MMBtu/d service throughput for Southern Dome, a majority-owned affiliate.

Appendix

Copano Energy

Oklahoma Net Commodity
Exposure

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

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

(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.

Appendix

Copano Energy

Oklahoma Commodity Price
Sensitivities

• Oklahoma segment gross margins excluding hedge
settlements

– Matrix reflects 4Q 2009 volumes, adjusted using Copano’s
2009 planning model

Appendix

Copano Energy

Texas Contract Mix

Appendix

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

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

Copano Energy

Texas Net Commodity Exposure

Note: See explanation of processing modes in this Appendix.

(1) Source: Copano Energy internal financial planning models for consolidated subsidiaries. Based on 4Q 2009
daily wellhead/plant inlet volumes.

(2) 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.

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

Appendix

Copano Energy

Texas Commodity Price
Sensitivities

• Texas segment gross margins excluding hedge settlements

– Matrix reflects 4Q 2009 volumes and operating conditions,
adjusted using Copano’s 2009 planning model

Appendix

Copano Energy

Rocky Mountains Sensitivities

Appendix

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.

• 4Q 2009

– Adjusted EBITDA volume sensitivity (positive or negative impact)

• Consolidated (producer services): 10,000 MMBtu/d = $26,000

• Unconsolidated affiliates:

§ Bighorn: 10,000 MMBtu/d = $227,000(1)

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

Copano Energy

Hedging Impact
of Commodity Price Sensitivities

• Commodity hedging program supplements cash flow in 2010
through 2012 during less favorable commodity price periods

Appendix

Copano Energy

Liquidity and Debt Facilities

• At December 31, 2009:

– Cash: $45 million

– $550 million revolving credit facility

• Approximately $122 million available (limited by debt covenants) -
availability increased to approximately $264 million pro forma for March
2010 equity offering

• Remaining term: approximately 2.8 years

• LIBOR + 175 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: 7.1 years

Appendix

Note: See slide titled “Recent Equity Offering” for adjusts related to March 2010 equity offering.

Copano Energy

• Senior Secured Revolving Credit Facility

– $550 million facility with $100 million accordion

– Maintenance tests:

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

§ 4.39x at December 31, 2009 (3.67x pro forma for March 2010 equity
offering)

• Minimum required interest coverage 2.5x defined EBITDA

§ 3.59x at December 31, 2009

• 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

Key Debt Terms and Covenants

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

Appendix

Copano Energy

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.

• The following table presents total segment gross margin and a reconciliation of total segment gross margin to the GAAP financial measure of operating
income:

Appendix

Copano Energy

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.

• The following table presents a reconciliation of the portion of our EBITDA and Adjusted EBITDA attributable to each of our segments to the GAAP financial
measure of net income (loss):

Appendix

Copano Energy

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):

Appendix

Copano Energy

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.

Appendix

Copano Energy

NASDAQ: CPNO

March 2010

Copano Energy, L.L.C. - FORM 8-K - EX-1 - MARCH INVESTOR PRESENTATION - March 8, 2010

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