Forward Looking Statements

January 2010 1

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 2

Company Overview 3

Key Business Highlights Leading Midstream Company Diversity of Services Leading midstream energy services company focused on gathering, processing, transmission and marketing natural gas and natural gas liquids ( NGLs ) Assets strategically located in key producing areas and market regions Focus on Barnett and Haynesville Shale plays Over 3,300 miles of natural gas gathering and transmission pipeline 9 natural gas processing plants 3 fractionators Over 400 miles of NGL pipelines 2.4 MM barrels of NGL storage capacity Transmission Lines Natural Gas Consumers Gathering, Dehydration & Compression NGL Transportation & Fractionation NGL Markets Wellhead Processing,Conditioning & Treating 4

Strategically Located Assets North Texas ~780 miles of pipeline 3 processing plants LIG ~2,100 miles of pipeline 2 processing plants Processing & NGLs ~440 miles of NGL pipeline 4 processing plants 2 fractionation facilities 5

Focused Business Strategy Capitalize on strategic positions in key domestic shale regions Significant positions in Barnett and Haynesville Shales ~3 Bcf/d volume (~6% of U.S. production) Improved risk profile Moving to fee-oriented contracts Expansion risks mitigated by customer commitments; gating process Direct commodity exposure limited through active hedging program Decrease financial leverage Focus on higher return projects Lean organization Conservative financial guidelines 6

Key Investment Highlights Successfully executed 2009 plan Reduced debt by over $500 MM through asset sales during a challenging financial market Completed $125 MM preferred equity offering on January 19, 2010 Improved predictability of cash flow stream ~75% - 85% of YTD (1) gross margin derived from fee and margin activities (not directly exposed to commodity prices) Focus on core asset position in north Texas and Louisiana, especially established shale positions Execute bolt-on, high-return projects to leverage existing strategic asset base (1) Nine months ended September 30, 2009. 7

Executing Our Plan The Plan Accomplishments 1. Sell Non-core Assets - Seminole Plant interest & Arkoma assets $96 MM - Mississippi and South Texas assets $220 MM - Treating assets $266 MM - East Texas assets $40 MM Total $622 MM 2. Invest in High Return Projects - 2009 Capex focused on high return, low risk projects 3. Maximize Operating Efficiencies - Additional savings above initial 2009 projection 4. Continue To Improve Results - Increased adjusted cash flow guidance by ~ $30 MM for 2009 5. Access Equity Markets - Completed $125 MM of preferred equity 6. Re-Position Balance Sheet In Progress - Positioned to complete in 2010 7. Restore Distributions/Dividends Pending - Consistent with our financial guidelines 8

Core Assets have Track Record of Growth and Performance Gross Margin (1) ($ in millions) $500 Adjusted EBITDA From Continuing Operations (1) ($ in millions) $250 CAGR 26% CAGR 44% $400 $200 $300 $260 $308 $296 $150 $127 $165 $161 $200 $100 $158 $100 $50 $59 $0 2006 2007 2008 LTM (2) $0 2006 2007 2008 LTM (2) Capital Expenditures ($ in millions) Pipeline Throughput Volumes (1) (MMBtu/d) $500 $400 $300 $6 $11 $18 3,000,000 2,400,000 1,800,000 1,555,000 CAGR 37% 1,991,000 2,060,474 $200 $100 $0 $309 $404 $257 2006 2007 2008 (2) (2) LTM 2006 2007 2008 LTM Maintenance Capex Growth Capex (1) Based on continuing operations; See reconciliation to net income in appendix (2) LTM as of September 30, 2009 $13 $135 1,200,000 600,000 0 845,000 9

North Texas 10

North Texas: Strategically Positioned for Barnett Shale North Texas Pipeline & Gathering Systems Gulf Crossing / NGPL Processing Plant New, well-positioned assets Denton Gathering 2004 North Texas Pipeline 2005 Chief Acquisition 2006 Azle /Goforth Plants 2006 Silvercreek Plant 2007 Gathering build-out continues Experience gained for future shale play activity 11 11

Successful Execution of Strategy Gathering and Transmission Throughput (MMBtu/d) 1,500,000 1,200,000 1,017,000 900,000 604,000 600,000 300,000 115,000 0 1,154,000 Favorable Contract Mix Key Assets Average terms for remaining gathering and transmission contracts are ~9 years and ~6 years, respectively Contracts are supported by dedicated acres, volumetric commitments and demand charges 2006 2007 2008 YTD 9/30/09 Gathering and Transmission Systems Gas Processing Volumes (MMBtu/d) ~640 miles of gathering pipelines (including NGL pipelines) 250,000 200,000 165,000 226,000 224,000 North Texas Pipeline ~140 mile transmission system with 375 MMcf/d of takeaway capacity 150,000 100,000 50,000 18,000 Processing Facilities 3 Cryogenic plants with 280 MMcf/d processing capacity 0 2006 2007 2008 YTD 9/30/09 12

Barnett Shale: Key Takeaways Is the Barnett Shale still a growing unconventional resource play? Yes. - Confirmed by recent M&A activity and 3 rd party reserve engineering study Do E&P companies have the liquidity needed to develop the Barnett? Yes. - Chesapeake s JV with Total - Devon pivots away from offshore/international to onshore shale plays - XTO is being acquired by Exxon - Quicksilver s JV with Eni Is Crosstex s current infrastructure well positioned to capture future growth? Yes. - Majority of pipe and processing plants are located in Core and Tier I of Barnett, where majority of future drilling is expected Are technological breakthroughs having an impact on the play? Yes. - EUR s and Practical IP rates are at all time highs - Producers drilling longer laterals with more frac stages 100 Drilling Rigs (Avg.) 50 116 72 70 82 84 Source: Rig Data (1) As of Jan. 2010 0 Q1 2009 Q2 2009 Q3 2009 Q4 2009 Currently (1) 13

Louisiana 14

Louisiana Overview One of the largest intrastate pipeline systems in Louisiana Continue to capture increased Haynesville volumes Serving interstate pipeline & industrial river markets LIG System NGL System Processing Plant 15

LIG Asset Overview System: ~2,100 miles of gathering/transmission YTD Throughput: 907,000 MMBTUD (1) 330 MMCFD Processing Capacity Markets: Industrial Power/Utility Southern Louisiana/Mississippi River Interstate Pipelines Haynesville Opportunity: Strategic position Haynesville drilling activity increasing Current Haynesville Capacity Expansions: Bolt On to original capacity Low cost, high return projects Underwritten by long-term, firm transportation contracts with major producers (1) Nine months ended September 30, 2009. Gathering and Transportation Volumes (MMBtu/d) 1,200,000 1,000,000 800,000 600,000 400,000 200,000 0 701,000 932,000 923,000 907,000 2006 2007 2008 YTD (1) 16

LIG: Haynesville Projects Original Red River Project 240 MMcf/d (100% Contracted) Black Lake Interconnect Phase III 35 MMcf/d (100% Contracted) North LIG Expansion Phase I/II 135 MMcf/d (100% Contracted) Partial System Loop Phase IV 145 MMcf/d Contract under negotiation Completed Project Project In Progress 17

Producer Activity Continues to Present New Opportunities Drilling in Haynesville has been successful to date and is driving higher producer activity The number of drilling rigs in the Haynesville continues to increase Crosstex s pipelines are in the core of the Louisiana Haynesville acreage Drilling Permits Drilling Rigs 3,000 120 115 2,400 2,506 100 93 1,800 1,613 80 60 58 68 1,200 995 40 600 20 0 2007 2008 2009 0 (1) (1) (2) 2007 2008 2009 Current Source: Baker Hughes Inc. (1) 2009 data, as of 9/30/09. (2) As of January 15, 2010. 18

Processing & NGLs: Business Strategy Integrated midstream assets located on gulf coast of Louisiana 4 Cryogenic plants 2 Fractionation Facilities ~400 miles of gathering and distribution lines with access to petro-chemical and refinery markets NGL System LIG System Processing Plant 19

Processing & NGLs: System Overview Integrated midstream asset group located on the Gulf Coast of South Louisiana Experienced full service NGL marketing Key Assets and distribution team 4 cryogenic gas processing facilities 2 NGL fractionation facilities ~400 miles of integrated gathering and distribution lines with access to petrochemical and refinery markets Pelican Processing Facility 2 facilities with 2.4 MMbbls of aggregate NGL storage capacity 2 barge docks 20 rail car loading racks Recently purchased Eunice processing plant and fractionation from Philip Morris for $42 million Increases EBITDA by ~$12 million per annum through lease elimination Recently purchased Intracoastal pipeline from Chevron for ~$10 million Serves as a link between Pelican and the NGL system 20

Financial Overview 21

Current Financial Focus Liquidity Deleveraging Improving cash flows Focus on high return investments Re-position balance sheet Restore distributions/dividends 22

Core Assets have Track Record of Growth and Performance Gross Margin (1) ($ in millions) $500 Adjusted EBITDA From Continuing Operations (1) ($ in millions) $250 CAGR 26% CAGR 44% $400 $200 $300 $260 $308 $296 $150 $127 $165 $161 $200 $100 $158 $100 $50 $59 $0 2006 2007 2008 LTM (2) $0 2006 2007 2008 LTM (2) Capital Expenditures ($ in millions) Pipeline Throughput Volumes (1) (MMBtu/d) $500 $400 $300 $6 $11 $18 3,000,000 2,400,000 1,800,000 1,555,000 CAGR 37% 1,991,000 2,060,474 $200 $100 $0 $309 $404 $257 2006 2007 2008 (2) (2) LTM 2006 2007 2008 LTM Maintenance Capex Growth Capex (1) Based on continuing operations; See reconciliation to net income in appendix (2) LTM as of September 30, 2009 $13 $135 1,200,000 600,000 0 845,000 23

Conservative Financial Guidelines Fund organic growth and strategic opportunities with internal cash flows and with a balanced mix of debt and equity Allocate capital to high-return projects with predictable cash flows Preliminary 2010 capital expenditure budget for growth projects of ~$23 million Maintain a balanced contract mix and an active commodity price hedging program consistent with risk management guidelines No speculative hedging positions, no compensation for taking positions Utilization of product-specific swaps Maintain adequate liquidity to manage business cash flow requirements, margin requirements and business risks Maintain a conservative capital structure and leverage ratios Deleverage to achieve Debt / EBITDA of 4.5x before considering payment of distributions 24

Commodity Sensitivity Annual Impacts ± $.10 NGL Pricing (POL)- $3.0 MM (Net of Hedges) ± 5% NGL- Gas Ratios(Proc Margin)- $1.7 MM (Net of Hedges) Hedged Volume as a % of Hedgeable Volume 2010 Q1 Q2 Q3 Q4 POL Total VAR Volumes 10.27 10.08 9.40 10.13 Total Hedgeable Volumes 3.89 3.76 3.69 3.99 Total Hedged Volumes 3.64 3.08 1.27 1.79 Hedged Percentage 93% 81% 34% 44% Proc Margin Total VAR Volumes 12.89 12.17 17.17 15.53 Total Hedgeable Volumes 6.80 6.90 7.00 7.03 Total Hedged Volumes 5.74 5.20 2.41 3.06 Hedged Percentage 84% 67% 42% 54% Note: all volumes are in millions of gallons 25

Diversified Revenue Sources YTD GROSS MARGIN BY CONTRACT TYPE Processing Margin 8% Fee Based 12% Percent of Liquids 13% Gathering and Transportation 67% Note: As of September 30, 2009. 26

2009 Adjusted EBITDA Bridge* 2009 Adjusted EBITDA Bridge* ($MM) Range of Guidance $197 MM to $207 MM $200 $150 $172 $30 $202 ($40) $161 $36 PM/POL (6) Estimated Incremental Impact of 2009 Transactions Eunice Lease Unwind - $10.0 MM $100 Intracoastal Lease Unwind - $1.3 MM Balance of year for 100 MMcf/d Red River $50 $125 G &T/ Fee Lateral Expansion - $6.8 MM Balance of year for Black Lake Expansion - $4.2 MM Total- $22.3 MM $0 2009 EBITDA Guidance (1) EBITDA Improvements (2) 2009 Revised (3) Asset Sales Impact (4) 2009 Run Rate EBITDA (5) * Estimated (1) Represents estimated 2009 Adjusted EBITDA guidance adjusted for the impact of asset sales (2) 2009 EBITDA Improvements includes $5 mm operating expense savings and gross margin increases of $18 mm on LIG and $7 mm on SLPN (3) Represents mid-point of current estimated 2009 Adjusted EBITDA, which is preliminary and subject to year end audit adjustments (4) Represents actual Adjusted EBITDA contribution from sold assets (5) 2009 Adjusted EBITDA from continuing operations (6) 2009 realized weighted average liquids price was $0.81 per gallon; 2009 average natural gas price was $3.94 per MMBtu(Gas Daily Henry Hub) 27 27

Key Investment Highlights Successfully executed 2009 plan Reduced debt by over $500 MM through asset sales during a challenging financial market Completed $125 MM preferred equity offering on January 19, 2010 Improved predictability of cash flow stream ~75% - 85% of YTD (1) gross margin derived from fee and margin activities (not directly exposed to commodity prices) Focus on core asset position in north Texas and Louisiana, especially established shale positions Execute bolt-on, high-return projects to leverage existing strategic asset base (1) Nine months ended September 30, 2009. 28

Appendix 29

Proposed Senior Credit Facility Borrower: Crosstex Energy, L.P. Guarantors: All material subsidiaries now existing or hereafter created or acquired Facility: Up to $450 MM Senior Secured Revolving Credit Facility (the Revolver ) Maturity: 4 Years Security: First priority lien on substantially all assets of the Borrower Financial Covenants: Maximum Total Leverage Ratio of 5.75x with step-downs to 4.50x Maximum Senior Secured Leverage Ratio of 2.50x Minimum Interest Coverage Ratio of 1.50x with step-ups to 2.50x Pricing: Applicable Margin Funded Debt/ Commit LIBOR+ ABR+ EBITDA Fee 5.0x 4.25% 3.25% 0.50% 4.5x 4.00% 3.00% 0.50% 4.0x 3.75% 2.75% 0.50% 3.5x 3.50% 2.50% 0.50% < 3.5x 3.25% 2.25% 0.50% 30 30 30

Summary Terms of Preferred Units Issuer: Purchaser: Investment / Amount: Number of Units / Price: Use of Proceeds: Distributions: Conversion: Board of Directors: Crosstex Energy, L.P. ( XTEX ) GSO Crosstex Holdings LLC $125 MM convertible preferred units 14.7 million preferred units at $8.50 per unit Net proceeds used to repay indebtedness at XTEX XTEX will pay quarterly on the preferred units in cash or in-kind, or any combination thereof (the form of distribution to be as determined by XTEX); provided that XTEX may not pay distributions in-kind for any quarter in which cash distributions are paid on the XTEX common units. The preferred units will be convertible into common units any time at the Purchaser s election on a one-for-one basis, subject to anti-dilution adjustments. After the three year anniversary of closing, XTEX may, at its election, cause conversion of the preferred units if (i) the weighted average trading price exceeds $12.75 subject to anti-dilution adjustments for 20 trading days and (ii) the average daily trading volume of common units over the same period exceeds 250,000. The Purchasers received one seat on the XTEX General Partner s Board of Directors 31

EBITDA Reconciliation ($ in millions) 9 Months Ended LTM 2007 2008 9/30/08 9/30/09 9/30/09 Net Income $13.9 $10.8 $20.2 $48.5 $39.1 Income from discontinued operations, net of tax (31.3) (74.8) (21.8) (101.8) (154.8) Interest expense 48.1 75.0 34.0 67.1 108.1 Depreciation and Amortization (1) 83.1 107.2 79.0 89.7 118.0 Impairment 0.0 29.4 0.0 0.9 30.3 Other (2) 14.2 17.7 9.2 11.5 20.0 Adjusted EBITDA $126.9 $165.3 $120.6 $116.0 $160.6 (1) Net of minority share of depreciation and amortization. (2) Includes stock based compensation; financial derivatives marked-to-market; deferred taxes; loss on extinguishment of debt; severance and exit expenses and adjustment for idle property sales proceeds in excess of gain on sale included in net income. 32

Hedge Positions ($ in millions) Notional Product Period Underlying Volume/Amount We Pay We Receive Gas Processing October 2009-December 2009 October 2009-December 2009 October 2009-December 2009 October 2009-December 2009 October 2009-December 2009 January 2010 December 2010 January 2010 December 2010 January 2010 December 2010 Ethane 34 (MBbls) Index $0.6401 ($/gallon) Propane 27 (MBbls) Index $1.2771 ($/gallon) Iso Butane 5 (MBbls) Index $1.7179 ($/gallon) Normal Butane 10 (MBbls) Index $1.5320 ($/gallon) Natural Gasoline 20 (MBbls) Index $2.0257 ($/gallon) Propane 109 (MBbls) Index $0.9584 ($/gallon) Normal Butane 40 (MBbls) Index $1.2580 ($/gallon) Natural Gasoline 21 (MBbls) Index $1.4815 ($/gallon) Fractionation October 2009 December 2009 October 2009 December 2009 October 2009 December 2009 October 2009 December 2009 October 2009 December 2009 October 2009 December 2009 January 2010 December 2010 January 2010 December 2010 January 2010 December 2010 January 2010 December 2010 January 2010 December 2010 Ethane 39 (MBbls) Index $0.44/gal* Propane 24 (MBbls) Index $0.8148/gal* Iso-Butane 1 (MBbls) Index $1.105/gal* Normal Butane 15 (MBbls) Index $1.0263/gal* Natural Gasoline 16 (MBbls) Index $1.385/gal* Natural Gas 4,822 (MMBtu/d) $4.8225/MMBtu* Index Ethane 127 (MBbls) Index $0.4607/gal* Propane 85 (MBbls) Index $0.9226/gal* Normal Butane 57 (MBbls) Index $1.2007/gal* Natural Gasoline 56 (MBbls) Index $1.5305/gal* Natural Gas 4,269 (MMbtu/d) $5.7672/MMBtu* Index * Weighted Average Note: Figures as of September 30, 2009. 33