Copano Energy, L.L.C. - FORM 8-K - EX-1 - JANUARY 2010 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

January Investor Presentation

NASDAQ: CPNO

January 26, 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 expects, believes or
anticipates will or may occur in the future are forward-looking statements. Underlying these
forward-looking statements are certain assumptions made by Copano’s management based on
their experience and perception of historical trends, current conditions, expected future
developments and other factors management believes are appropriate under the circumstances.

Whether actual results and developments in the future 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

• Founded in 1992 as an independent midstream company

• Serves natural gas producers in three producing areas

Texas

South Texas and

North Texas

Oklahoma

Central and Eastern Oklahoma

Rocky Mountains

Wyoming’s Powder River Basin

Copano Energy

Key Metrics

• Service throughput volumes approximate 2 Bcf per day of natural
gas(1)

• Approximately 6,700 miles of active pipelines

• 7 natural gas processing plants with over 1 Bcf/d of combined
processing capacity

• Equity market cap: $1.5 billion(2)

• Enterprise value: $2.3 billion(2)

(1) Based on 3Q09 results. Includes unconsolidated affiliates.

(2) As of January 21, 2010.

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

Throughput
Volume Outlook

Commodity
Prices and
Margin
Sensitivities

Capital and
Liquidity

Distribution Policy
and Outlook

Copano Energy

• Total service throughput volumes decreased 3% from 2Q09 to 3Q09

• Processed volumes decreased 2% from 2Q09 to 3Q09

Total Volume Trends

Note: Includes affiliates, net of intercompany volumes.

Copano Energy

• Rich gas (primarily Hunton de-watering play)

– Drilling activity remains steady with current commodity prices
and long-term price outlook

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

– High BTU gas, processing upgrade and low geologic risk
enhance drilling economics, but activity remains subject to
market conditions

– 4Q09 volumes are expected to be down vs. 3Q09 due to
delayed down-hole repair schedules, shut-in volumes and
weather related issues

• Lean gas (primarily Woodford Shale and Coalbed methane)

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

– 8 rigs currently running

– 4Q09 volumes are expected to be slightly down from 3Q09
due to normal declines and lag between drilling and production

Oklahoma Volume 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 1/21/10

Copano Energy

South Texas Volume Outlook

• Recently connected a third Eagle Ford Shale well, which IP’d at
17 MMcf/d

• In 4Q09, announced plans for a joint venture with Kinder Morgan
to provide gathering, transportation and processing services to
gas producers in the Eagle Ford Shale

• 4Q09 volumes are expected to be slightly down from 3Q09

• In December 2009, FERC issued an order denying Transco
authority to abandon its McMullen Lateral pipeline in South Texas
by sale to Copano. Copano and Transco will not file for rehearing

Copano Energy

Texas Fractionation Strategy

• Capacity at NGL fractionation facilities along the Texas Gulf Coast
remains constrained

• Utilizing Houston Central’s fractionation unit and extensive tailgate
NGL pipelines, Copano plans to produce purity products by 2Q10

– Copano is expanding its de-ethanization capacity in order to produce
purity ethane and propane

– Iso-butane and normal butane will be sold as purity products by tank truck

Copano Energy

North Texas Volume Outlook

• 9 rigs running in the area with
an additional 2-4 rigs
anticipated in 1Q10

• 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, plant inlet volumes
are expected to steadily
increase in 2010

Copano Energy

Rocky Mountains Volume Outlook

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

• 4Q09 volumes are expected to be flat vs. 3Q09 due to previously
drilled wells

• 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

• On Fort Union, during the third and fourth quarters, roughly 150
MMcf/d was temporarily shut in by producers due to commodity prices;
by mid-October, volumes were back to near pre-shut-in levels

Copano Energy

Commodity Prices and Margin
Sensitivities

Commodity
Prices and
Margin
Sensitivities

Distribution Policy
and Outlook

Capital and
Liquidity

Throughput
Volume Outlook

Copano Energy

Oklahoma Commodity Prices

Copano Energy

Actual Prices: 1/08 - 1/10

Forward Prices as of 1/21/10: 2/10 - 12/13

Oklahoma Natural Gas Price
Outlook

Copano Energy

Texas Commodity Prices

Copano Energy

Actual Prices: 1/08 - 1/10

Forward Prices as of 1/21/10: 2/10 - 12/13

South Texas Natural Gas Price
Outlook

Copano Energy

Actual Prices: 1/08 - 1/10

Forward Prices as of 1/21/10: 2/10 - 12/13

Rocky Mountains Natural Gas Price
Outlook

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 3Q09 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

(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.

Copano Energy

Capital and Liquidity

Capital and
Liquidity

Distribution Policy
and Outlook

Commodity
Prices and
Margin
Sensitivities

Throughput
Volume Outlook

Copano Energy

2010 Expansion Capital

• Copano has approximately $105 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

– Saint Jo processing plant and pipelines in north Texas

– Additional pipeline and processing capacity in Oklahoma

• 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

Liquidity and Debt Facilities

• At September 30, 2009:

– Cash: $35 million

– $550 million revolving credit facility

• Approximately $290 million available

• Remaining term: approximately 3.1 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: 7.4 years

Copano Energy

• Senior Secured Revolving Credit Facility

– $550 million facility with $100 million accordion

– Maintenance tests:

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

§ 3.99x at September 30, 2009

• Minimum required interest coverage 2.5x defined EBITDA

§ 3.41x at September 30, 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 Appendix for reconciliation of defined EBITDA, which is referred to in our credit facility as “Consolidated
EBITDA.”

Copano Energy

Distribution Policy and Outlook

Distribution Policy
and Outlook

Capital and
Liquidity

Commodity
Prices and
Margin
Sensitivities

Throughput
Volume 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

Driver	Potential 2011 - 2012 Annual Incremental Total DCF Impact(1) ($ in millions)	Comments and Risk Factors
Forward Commodity Prices (3Q09 vs. 2012 forward curve(2) and without hedges)	$60	• Reflects January 2010 forward curve(2) • Future market conditions
North Texas	$35 - $45	• Resource play • Drilling activity • Product prices
South Texas Fractionation Expansion and Development Projects (2)	$25 - $30	• Eagle Ford Shale development • Drilling activity • Product prices • New attachments

(1) Compared to 3Q09 annualized levels. See Appendix for an explanation of how we calculate total distributable
cash flow.

(2) Reflects January 2010 forward price curves with regression-based NGL prices.

Copano Energy

Distribution Outlook

Driver	Potential 2011 - 2012 Annual Incremental Total DCF Impact(1) ($ in millions)	Comments and Risk Factors
Oklahoma Volumes(2)	$15 - $20	• Resource play • Drilling activity • Product prices
Rocky Mountains	$10 - $20	• Resource play • Drilling activity • Dewatering rates • New projects
Future Acquisitions and Major Projects	TBD	• Build-out of Corporate Development team • Opportunities • Execution

(1) Compared to 3Q09 annualized levels. See Appendix for an explanation of how we calculate total distributable
cash flow.

(2) Reflects January 2010 forward price curves with regression-based NGL prices.

Copano Energy

• On October 14, 2009, EnergyPoint Research, Inc. announced
results of its Natural Gas Midstream Services Survey

• Copano placed first overall among 16 midstream energy
companies. Copano also rated first in many categories for
gathering and processing/treating

#1 in Customer Satisfaction

Copano Energy

• Current cash flow trends remain solid

• Forward market prices should support continued drilling activity in
our cost-competitive operating regions

• Copano’s liquidity and access to capital remain strong

• Copano continues to enjoy an abundant opportunity environment

Conclusions

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 Commercial Update

• Third Quarter 2009

– Total service throughput volumes: 260,000 MMBtu/d(1)

– Unit margin: $0.76/MMBtu(2)

– Margins from approximately 75% of contract volumes are directly
correlated with NGL prices

– Significant percentage of contract volumes (51%) contain fee-based
components, including volumes subject to minimum margin provisions

• Operated in full processing mode for third and fourth quarter 2009

(1) Excludes 13,857 MMBtu/d service throughput for Southern Dome, a majority-owned affiliate.

(2) Refers to Oklahoma segment gross margin ($18.3 million) divided by Oklahoma service throughput volumes
(268,000 MMBtu/d) for the period. See this Appendix for reconciliation of Oklahoma segment gross margin.

Appendix

Copano Energy

Oklahoma Contract Mix

• Third quarter 2009 contract mix(1)

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

(2) Excludes 13,857 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 3Q09 volumes, adjusted using Copano’s 2009
planning model

Appendix

Copano Energy

Texas Commercial Update

• Third Quarter 2009

– Total service throughput volumes: 613,000 MMBtu/d(1)

– Unit margin: $0.48/MMBtu(2)

– Margins from approximately 85% of contract volumes are directly
correlated with NGL prices

– Approximately 91% of contract volumes have fee-based components,
including volumes subject to minimum margin provisions

• Operated in full processing mode for third and fourth quarter 2009

(1) Excludes 72,985 MMBtu/d service throughput for Webb Duval, a majority-owned affiliate.

(2) Refers to Texas segment gross margin ($26.9 million) divided by Texas service throughput volumes (613,000
MMBtu/d) for the period. See this Appendix for reconciliation of Texas segment gross margin.

Appendix

Copano Energy

Texas Contract Mix

• Third quarter 2009 contract mix(1)

Appendix

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

(2) Excludes 72,985 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 3Q09 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 3Q09 volumes and operating conditions,
adjusted using Copano’s 2009 planning model

Appendix

Copano Energy

Rocky Mountains Commercial
Update

• Third Quarter 2009

– Total service throughput volumes:

• Consolidated affiliates (producer services): 157,000 MMBtu/d

• Unconsolidated affiliates:

§ Bighorn: 190,000 MMBtu/d

§ Fort Union: 762,000 MMBtu/d

• All Bighorn and Fort Union margins are fixed fee

• Virtually all producer services margins are fixed margin

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.

• Third Quarter 2009

– Adjusted EBITDA volume sensitivity (positive or negative impact)

• Consolidated (producer services): 10,000 MMBtu/d = $28,000

• Unconsolidated affiliates:

§ Bighorn: 10,000 MMBtu/d = $249,000(1)

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

Copano Energy

Rocky Mountains Takeaway
Capacity Outlook

Source: Bentek Energy, LLC

(1) Historical and future prices as of 1/5/10. 1/21/10 spot: $5.095/Mcf

(1)

Appendix

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

Hedging Impact

• 2010 NGLs Hedge Settlement Matrix

Note: All hedge instruments are reported in Copano’s SEC filings. Hedge settlements are based on monthly average
Mt. Belvieu NGL and NYMEX WTI prices. Positive amounts reflect payments from hedge counterparties under
swap and put option instruments. Negative amounts reflect payments to hedge counterparties under swap
instruments.

Appendix

Copano Energy

Hedging Impact

• 2011 NGLs Hedge Settlement Matrix

Appendix

Copano Energy

Hedging Impact

• 2012 NGLs Hedge Settlement Matrix

Appendix

Copano Energy

Hedging Impact

• 2009 - 2011 Natural Gas Hedge Settlement Matrix(1)

Note: All hedge instruments are reported in Copano’s SEC filings. Hedge settlements are based on first of the month
Houston Ship Channel and CenterPoint East natural gas prices. Positive amounts reflect payments from hedge
counterparties under call and put option instruments.

(1) Not included in the matrix, for calendar 2010, Copano entered into a basis spread between Houston Ship Channel
and Centerpoint East natural gas indices to lock in the basis between the two indices for 10,000 MMBtu/d of
natural gas at $0.185/MMbtu.

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.

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

January 2010

Copano Energy, L.L.C. - FORM 8-K - EX-1 - JANUARY 2010 INVESTOR PRESENTATION - January 26, 2010

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