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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

March 8, 2010

Copano Energy
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
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
  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
Typical MLP
Copano Energy
Tax Shield on
Tax Reporting
General Partner
Distribution Rights
Voting Rights
Schedule K-1
Schedule K-1
Form 1099

Copano Energy
2010 Regional
Prices and
Financing and
Commodity Risk
Outlook and

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
  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
  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
 $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
 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
 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
 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
Prices and
Outlook and
Financing and
Commodity Risk
2010 Regional

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.

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
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
Financing and
Commodity Risk
Outlook and
Prices and
2010 Regional

Copano Energy
2010 Expansion Capex
 Copano has approximately $130 million(1) in approved
 expansion capital projects for 2010. Major areas of focus
  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
  Proceeds used to reduce revolver borrowings, which ultimately
 will fund expansion capex
  Demonstrated commitment to raising capital and maintaining
 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

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
Outlook and
Financing and
Commodity Risk
Prices and
2010 Regional

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
(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
  Explore opportunities beyond traditional gathering and
  Be more proactive in seeking assets and opportunities
  Reduce sensitivity of cash flows to commodity price
  Hedging program
  Contracts - increase fee-for-service component
Growth Strategy

Copano Energy

Copano Energy
Oklahoma Assets

Copano Energy
South Texas Assets

Copano Energy
North Texas Assets

Copano Energy
Rocky Mountains Assets

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 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)

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.

Copano Energy
Oklahoma Net Commodity
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.

Copano Energy
Oklahoma Commodity Price
 Oklahoma segment gross margins excluding hedge
  Matrix reflects 4Q 2009 volumes, adjusted using Copano’s
 2009 planning model

Copano Energy
Texas Contract Mix
(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.

Copano Energy
Texas Commodity Price
 Texas segment gross margins excluding hedge settlements
  Matrix reflects 4Q 2009 volumes and operating conditions,
 adjusted using Copano’s 2009 planning model

Copano Energy
Rocky Mountains Sensitivities
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

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
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
  Minimum required interest coverage 2.5x defined EBITDA
 § 3.59x at December 31, 2009
  Defined EBITDA adds back hedge amortization and other non-cash
  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.”

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

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):

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):

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.

Copano Energy
March 2010