Bank of America Merrill Lynch Leveraged Finance Conference December - - PowerPoint PPT Presentation

1

Barry E. Davis President and CEO Bank of America Merrill Lynch Leveraged Finance Conference December 1, 2011

Forward Looking Statements

This presentation contains forward looking statements within the meaning of the federal securities laws. Forward looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of Crosstex Energy, L.P. and its affiliates (collectively known as “Crosstex”) may differ materially from those expressed in the forward-looking statements contained throughout this presentation and in documents filed with the SEC. Many of the factors that will determine these results are beyond Crosstex’s ability to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future, including, among others, the ability to achieve synergies and revenue growth; national, international, regional and local economic, competitive and regulatory conditions and developments; technological developments; capital markets conditions; inflation rates; interest rates; the political and economic stability of oil producing nations; energy markets; weather conditions; business and regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity; the timing and success of business development efforts; and other uncertainties. You are cautioned not to put undue reliance on any forward looking statement. Crosstex has no obligation to publicly update or revise any forward looking statement, whether as a result of new information, future events or otherwise.

2

3

• Midstream energy services company focused
• n full value chain
• Assets strategically located in key producing

areas and market regions

• Strategic focus on:
• Maximizing earnings and growth of

existing business

• Growing business to enhance scale and

diversification

Focused Midstream Company Diversity of Services

• Over 2,800 miles of natural gas gathering

and transmission pipeline

• 9 natural gas processing plants
• 3 fractionators
• Over 470 miles of NGL pipeline
• 2.4 MM barrels of NGL cavern storage

Petrochemical plants, Refineries & Other NGL Markets Wellhead Gathering, Dehydration, Compression & Treating Processing & Fractionation Transmission Lines NGL Transportation Natural Gas Consumers

Crosstex Energy

Strategically Positioned Assets

LIG

• ~2,100 miles of pipeline
• 2 processing plants
• 2 treating plants

PNGL

• ~440 miles of NGL pipeline
• 4 processing plants
• 3 fractionation facilities

North Texas

• ~840 miles of pipeline
• 3 processing plants
• 2 treating plants

Eagle Ford

• Strategic partnership

with Howard and Quanta to pursue opportunities in Eagle Ford

Permian

• 50 MMcf/d new build gas processing plant
• Mesquite rail terminal to transport stranded

NGLs from this region

Crude

• Crude rail unloading facilities
• n CN and UP railroads

4

Cajun Sibon

• ~130-mile NGL pipeline
• From Mt. Belvieu to

expanded fractionation assets in LA

5

Crosstex Today

Segment Cash Flow 2011 YTD* $94.8 47% $69.4 35% $35.9 18% $ in MM NTX LIG PNGL

North Texas

• ~85% of dedicated acres are in Core
• Remaining locations to be drilled should double existing well count

LIG

• Solid contracting for firm transport in Haynesville and market-based

services

• Exposure to Tuscaloosa Marine and Austin Chalk with growing producer

activity targeting liquids PNGL

• Leveraging available frac capacity, rail/ barge facilities, storage/

market connections

Key Performance Drivers 2011 EBITDA Guidance

• f $185MM
• $215MM*

* Through 3Q 2011. Segment Cash Flow is a non-GAAP financial measure. See Reconciliation: Segment Cash Flow

Financial Highlights 2011 YTD*

• YTD adjusted EBITDA* of $159.4M and YTD

DCF* of $89.8M

• YTD

distributions

• f

$0.91/unit with coverage of 1.43x and YTD dividends of $0.29/share

• Third Quarter Debt-to-EBITDA of 3.96 to 1
• No near term debt maturities and over

$300M available on revolver

• 2011E and 2012E growth capital of $133M

and $226M, respectively

Cajun Sibon NGL Expansion Strategically Located

6

• Project includes building ~130-mile NGL pipeline from Mt. Belvieu and

expanding fractionation assets in LA

• Estimated in service date in first half of 2013
• Estimated capital costs of ~$180MM to $220MM

Permian Basin Expansion Strategically Located

• Developing 20 mmcf/d refrigeration plant as interim solution and 50 mmcf/d cryogenic

facility as permanent processing solution

• Jointly invest $85MM with Apache; interim facility operational by Q1 2012
• Mesquite rail terminal (100% owned) acquired to transport stranded Permian Basin NGLs
• Apache plans to drill ~700 wells in 2011 in the Permian, and in 2012 have plans to drill a

similar number or more according to their third quarter 2011 earnings report

7

8

Eagle Ford Expansion Strategically Located

• Strategic partnership to pursue opportunities in Eagle Ford Shale; Crosstex and Quanta

Services each invested $35MM (35% ownership) in Howard Energy Partners

• Completed a 30-mile, 12-inch diameter pipeline expansion since acquisition
• Reviewing additional growth opportunities

• Unconventional resource plays focused on

crude and liquids are driving substantial increase in US crude production – Crude rig counts have increased from less than 400 to over 1,000 in the last 2 years

• Regional infrastructure bottlenecks have

created differentials to Louisiana Gulf Coast Crude (LLS) markets

• Eunice and Riverside have rail, truck,

pipeline, and barge facilities that are adding crude capabilities – Facilities to be modified to receive up to 5,000 Bbls/d in Phase 1, with capital expenditures less than $2M, and with contributions beginning in Q1 2012 – Ability to expand Riverside by an additional 8,000 barrels per day by second half of 2012

Crude Terminal Opportunity

9

200 400 600 800 1,000 1,200

North America Crude Rig Count

Source: Baker Hughes

Current Financial Focus

• Maintaining strong liquidity position

for flexibility – No near term debt maturities – Over $300 million available on revolver

• Maintaining conservative capital

structure and leverage ratios – Match distributions with more reliable cash flows – Reinvest excess coverage from less sustainable cash flows – Third Quarter 2011 Debt-to-EBITDA

• f 3.96 to 1
• Improving cash flows by:

– Investing in high-return projects – Improving efficiencies of existing assets

10

$0.25 $0.26 $0.29 $0.31 $0.31 $0.00 $0.05 $0.10 $0.15 $0.20 $0.25 $0.30 $0.35 3Q 2010 4Q 2010 1Q 2011 2Q 2011 3Q 2011 Crosstex Energy, L.P. Quarterly Distribution Per Unit

We remain committed to distribution growth while maintaining disciplined balance sheet management

2011 YTD* Coverage of 1.43x

* Through 3Q 2011

Solid Performance in All Core Areas

Note: Segment Cash Flow is a non-GAAP financial measure. See Appendix for a reconciliation to Segment Profit. * 2011 represents mid-point of guidance

• CAGR (2007 – 2011) for total segment cash flows of 9.4%
• PNGL’s focus on NGL opportunities has provided fee-based diversified cash

flows and improved business profitability

• NTX growth projects (Benbrook and Fossil Creek) drive solid growth in 2011

Segment Cash Flow 2007 2008 2009 2010 2011* ($ in Millions) NTX $62 $103 $113 $114 $126 LIG 72 82 80 82 85 PNGL 42 12 21 38 41 Total Asset Segments 176 197 214 235 252 Years Ended December 31, (Unaudited)

11

Guidance for 2011

Low High $ (27) $ 4 119 119 8 8 83 82 2 2 $ 185 $ 215 (2) (2) (83) (82) (14) (11) $ 86 $ 120 $ 50 $ 150 $ 0.83 $ 1.18 $ 60.21 $ 85.69 $ 4.50 $ 3.50 208.5% 381.6% $ 1.04 $ 1.20 $ 0.32 $ 0.40 XTXI Dividends per Share Total Year 2011 Key Assumptions for Forecast Weighted Average Liquids Price Crude ($/bbl) Natural Gas ($/MMbtu) Natural Gas Liquids to Gas Ratio XTEX Distribution per Unit Adjusted EBITDA* Taxes and other LOC Fees & Interest Maintenance capital expenditures Distributable cash flow* Growth Capital Net income Depreciation and amortization Stock-based compensation LOC Fees & Interest Taxes and other

* Adjusted EBITDA and Distributable cash flow are non-GAAP measures. There is a reconciliation of these non-GAAP measures to net income (loss) in the appendix.

12

13

Final Thoughts…

High quality core assets across the entire midstream value chain

1

Key growth projects poised to take advantage of macro trends

2

Strong balance sheet with great access to capital

3

Appendix

14

15

Reconciliation: Segment Cash Flow to Operating Income (loss)

* 2011 Represents mid-point of guidance ** Other includes the impact of LOC fees, Gain (Loss) on derivatives and stock-based compensation allocated to operations

Years Ended December 31, 2011 YTD (Amounts in Millions) 2007 2008 2009 2010 2011* through (Unaudited) Q3 Total Asset Team Segment Cash Flow 176 $ 197 $ 214 $ 235 $ 252 $ 200 $ Shared Services (11) (15) (14) (13) (14) (10) Other ** (3) (7) (3) 11 2 6 Asset Team Segment Profits 161 $ 176 $ 197 $ 233 $ 241 $ 196 $ Corporate Segment Profits 8 6 3

• Segment Profits

169 $ 182 $ 201 $ 233 $ 241 $ 196 $ General and administrative expenses (60) (69) (60) (48) (49) (38) Gain (loss) on derivatives 4 9 3 (9)

• (6)

Gain on sale of property 1 1 1 14

• Depreciation, amortization and impairment

(83) (137) (122) (113) (119) (93) Operating income (loss) 31 $ (14) $ 23 $ 77 $ 73 $ 59 $

16

Reconciliation: Net Income to Adjusted EBITDA and Distributable Cash Flows

Years Ended December 31

(Amounts in millions)

2010 2009 (Unaudited) Net income (loss) attributable to Crosstex Energy, L.P. $ (26) $ 104 Depreciation, amortization and impairments 113 122 Stock-based compensation 9 9 Interest expense, net 87 95 Loss on extinguishment of debt 15 5 Gain on sale of property (14) (183) Taxes and other 3 6 Adjusted EBITDA 187 159 Interest (1)(2)(3) (83) (86) Cash taxes and other (2) (2) Maintenance capital expenditures (11) (8) Distributable cash flow $ 91 $ 62

(1) Excludes debt issuance cost amortization of $0.7 million for the year ended December 31, 2010 (2) Excludes senior secured note make-whole and call premium paid-in-kind interest in the amount $0.9 million and $9.5 million for the years ended December 31, 2010 and December 31, 2009, respectively. (3) Excludes noncash interest rate swap mark –to –market of ($0.8) million for the year ended December 31, 2009.