Baytex Energy Trust

Energy Capital Investment Symposium Houston, Texas June 3, 2009 Anthony W. Marino, President and Chief Executive Officer Advisory In the interest of providing Baytex's unitholders and potential investors with information regarding Baytex, including management's assessment of Baytex's future plans and operations, certain statements made by the presenter and contained in these presentation materials (collectively, this "presentation") are "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995 and "forward-looking information" within the meaning of applicable Canadian securities legislation (collectively, "forward-looking statements"). The forward-looking statements contained in this presentation speak only as of the date of this presentation and are expressly qualified by this cautionary statement. Specifically, this presentation contains forward-looking statements relating to: the potential conversion of our legal structure from a trust to a corporation; the ability to use our tax pools to shelter our income from tax; oil and natural gas production; capital expenditures; drilling and operational plans; cash flow; cash distributions; funding sources for our cash distributions and capital program; reserves and reserve life index; reserve values; the net asset value of our trust units; our Seal heavy oil resource play, including our assessment of the cyclic steam pilot project, the viability and economics of long-term commercial development, resource potential, number of potential drilling locations, initial production rates, estimated recoverable reserves, drilling and completion costs per well, finding and development and operating costs, recovery factors and steam-oil ratios; oil and gas prices and differentials between light, medium and heavy oil prices; proposed pipeline infrastructure development; rates of return for our heavy oil projects; our Bakken/Three Forks, Viking and Mowry Shale light oil resources plays, including the number of potential drilling locations, initial production rates, estimated recoverable reserves and drilling and completion costs per well; our debt to cash flow ratio; and valuation metrics customarily used in the oil and gas industry. In addition, information and statements relating to reserves are deemed to be forward-looking statements, as they involve implied assessment, based on certain estimates and assumptions, that the reserves described exist in quantities predicted or estimated, and that the reserves can be profitably produced in the future. These forward-looking statements are based on certain key assumptions regarding, among other things: oil and natural gas prices and differentials between light, medium and heavy oil prices; well production rates and reserve volumes; our ability to add production and reserves through our exploration and development activities; capital expenditure levels; the availability and cost of labour and other industry services; the amount of future cash distributions that we intend to pay; interest and foreign exchange rates; and the continuance of existing and, in certain circumstances, proposed tax and royalty regimes. The reader is cautioned that such assumptions, although considered reasonable by Baytex at the time of preparation, may prove to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein as a result of numerous known and unknown risks and uncertainties and other factors. Such factors include, but are not limited to: general economic, market and business conditions; industry capacity; fluctuations in market prices for oil and natural gas; liabilities inherent in oil and natural gas operations; uncertainties associated with estimating oil and natural gas reserves; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; incorrect assessments of the value of acquisitions; fluctuations in foreign exchange or interest rates; stock market volatility and market valuations; geological, technical, drilling and processing problems and other difficulties in producing petroleum reserves; changes in income tax laws, royalty rates and incentive programs relating to the oil and gas industry and income trusts; changes in environmental and other regulations; risks associated with oil and gas operations; and other factors, many of which are beyond the control of Baytex. These risk factors are discussed in Baytex's Annual Information Form, Form 40-F and Management's Discussion and Analysis for the year ended December 31, 2007, as filed with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission. There is no representation by Baytex that actual results achieved during the forecast period will be the same in whole or in part as those forecast and Baytex does not undertake any obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable securities law. Capital Market Information Trust Units Trading Symbols Average Daily Volume (1) Units Outstanding (Current) Market Value of Equity / Enterprise Value Monthly Distributions Cash-on-Cash Yield (2) TSX: BTE.UN / NYSE: BTE TSX: 385,000 / NYSE: 166,000 106.6 million C$2.1 billion / C$2.5 billion C$0.12/unit (Payable June 15/09) 7.5% 6.5% Convertible Debentures Trading Symbol Principal Outstanding (Mar 31/09) Conversion Price Maturity Date TSX: BTE.DB C$10.3 million C$14.75 December 2010 9.625% Senior Subordinated Notes Principal Outstanding Maturity Date (1) (2) US$180 million July 2010 Average daily trading volumes based on last 20 trading days through April 30, 2009 The cash-on-cash yield is calculated by dividing the annualized distribution of C$1.44 by the closing price of Baytex units of C$19.25 on the TSX on May 28, 2009. Corporate History • Publicly-traded E&P corporation from 1993-2003 – One of only six independent E&P names from 1993 that are still traded on TSX – Heavy oil emphasis began in 1997 • Converted to income trust in September 2003 – Baytex Energy Trust and Crew Energy created from Baytex Energy Ltd. – Emphasized high capital efficiency and sustainability – Second highest total return among conventional trusts since inception • • Probable conversion back to corporation at end of 2010 Desirable attributes for an energy investment regardless of legal structure Corporate Strategies • Sustainable operational and financial model • Full-cycle exploration and development capability • Diversified product mix and competitive advantage in heavy oil • Multi-year, low-cost development inventory • Conservative payout ratio and capital discipline Operating Areas Product Mix Company Total = 40,000 boe/d Gas 23% Heavy Oil 59% Light Oil 18% Production Split by Jurisdiction US 1% Saskatchewan 43% Alberta 49% BC 7% Operating Performance 2009 Guidance 2005 Production Light oil & NGL (bbl/d) 3,842 2006 2007 2008 Q1 2009 3,735 (1) 5,483 7,595 7,120 7,300 Heavy oil (bbl/d) Natural gas (MMcf/d) Total (boe/d) 20,735 60.4 34,647 21,325 55.4 34,292 22,092 51.9 36,222 23,530 54.8 40,239 23,432 55.3 39,762 23,500 55.0 40,000 Capital Expenditures (C$ million) E&D Acquisitions (net) Total (1) 130 22 152 133 133 149 245 394 185 265 450 48 0 48 150 10 160 Excluding 2,100 bbl/d of SAGD production purchased on Oct 1/05 and sold on Dec 31/05 Payout Ratio - Net of DRIP (%) 100% 120% 20% 40% 60% 80% 0% Oct-03 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Monthly Distribution (C$) Payout Ratio - Net of DRIP (%) Distribution History 0.00 0.05 Monthly Distribution (C$) 0.10 0.15 0.20 0.25 0.30 Capital Program Efficiency 3-Year Average 2006-08 5-Year Average 2004-08 2004 FD&A Cost (P + P) Excluding FDC (C$/boe) Including FDC (C$/boe) Recycle Ratio (P + P) Excluding FDC Including FDC CAPEX as a % of Cash Flow * Exploration & Development Acquisitions Total Reserves Replacement (P+P) Exploration & Development Acquisitions 2005 2006 2007 2008 10.70 12.45 4.69 7.69 7.31 15.66 10.90 11.91 13.11 16.06 11.02 12.98 9.57 12.50 1.9 1.6 5.5 3.4 3.4 1.6 2.2 2.0 2.9 2.4 2.8 2.4 2.9 2.2 44% 86% 130% 71% 12% 83% 59% 59% 52% 86% 138% 37% 54% 91% 46% 51% 97% 49% 51% 100% 80% 132% 125% 128% 143% 1% 123% 151% 119% 112% 128% 91% 118% 106% Total 211% 253% 144% 274% 231% 218% 224% * Cash flow excludes realized hedging gains / losses Oil & Gas Reserves December 31, 2006 December 31, 2007 December 31, 2008 Proved plus Probable Light oil & NGL (Mbbl) Heavy oil (Mbbl) Natural gas (Bcf) Total (Mboe) 11,706 108,737 148.1 145,120 20,805 122,461 148.9 168,076 31,385 126,054 178.2 187,139 Reserve Life Index (years) 11.6 12.3 12.8 Working interest reserves per NI 51-101 as evaluated by Sproule Associates Limited. Reserves Growth Proved Oil-Equivalent Reserves (MMboe) 200 Probable 150 38 100 30 35 43 61 52 50 77 84 101 103 116 126 0 Dec 31/03 Dec 31/04 Dec 31/05 Dec 31/06 Dec 31/07 Dec 31/08 Reserve Value and NAV Reserve Value as of December 31, 2008 Before Tax and Discounted at (%/year) 10% (C$ million) 15% (C$ million) 20% (C$ million) C$ million PV10 of Proved plus Probable reserves Undeveloped land Estimated year-end net debt Asset retirement obligations Net asset value Diluted trust units (millions) Net asset value per trust unit 3,479 199 (522) (49) 3,106 98,391 $31.57 Reserve Category Proved Developed Producing Developed Non-Producing Undeveloped Total Proved Probable Total Proved Plus Probable 1,183 507 779 2,469 1,010 3,479 1,048 394 583 2,025 728 2,753 945 315 448 1,708 552 2,260 Year 2009 2010 2011 2012 2013 WTI (US$/Bbl) 53.73 63.41 69.53 79.59 92.01 Hardisty Heavy (C$/Bbl) 47.05 54.58 59.96 67.53 74.08 AECO (C$/MMbtu) 6.82 7.56 7.84 8.38 9.20 Inflation Rate (%) 2.0 2.0 2.0 2.0 2.0 FOREX ($US/$Cdn) 0.80 0.85 0.85 0.90 0.95 Notes: Reserve value as evaluated by Sproule Associates Limited based on forecast prices shown. Prices inflated 2% annually after 2013. Undeveloped land and ARO evaluated by Baytex. Diluted trust units include 0.71 million trust units issuable pursuant to outstanding convertible debentures. B.C. Alberta Sask. Seal - Heavy Oil Resource Play  B.C. Seal – Resource Potential Alberta  Sask. • 67,000 acres (105 sections) of 100% land • Estimated resource potential of prospective land = 50 million barrels of original oil in place (OOIP) per section • Primary (cold) development 10-12 wells per section CAPEX = $1.3 million/well, IP  200 bbl/d per well, P+P reserves = 307 Mbbl/well F&D cost = $4.25 per bbl OPEX = $3.35 per bbl (average for 2008) Recovery factor: 3-5% OOIP • Thermal development - Recovery factor: 20-50% OOIP B.C. Seal – Production Performance 6000 4 Hz wells drilled Q1/09 Alberta  Sask. 5000 4000 9 Hz wells drilled Q3-Q4/08 bbl / d 3000 2000 6 Hz wells drilled Q1/05 10 Hz wells drilled plus thermal pilot Q1-Q2/08 8 Hz wells drilled Q3/07 1000 0 Apr-05 9 Hz wells 2 Hz wells drilled Q1/07 drilled Q1/06 Apr-06 Apr-07 Apr-08 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Apr-09 Jul-05 Jul-06 Jul-07 Oct-05 Oct-06 Oct-07 Jul-08 Oct-08 B.C. Seal – Thermal Pilot Production Actual Cold 1000 900 Alberta  Sask. Projected Cold Post-Steam Barrels of Oil Per Day 800 Incremental SOR (deducting cold primary) = 1.3 700 600 500 Inject Steam / Soak Gross SOR (without deducting cold primary) = 0.8 400 300 200 100 0 Apr-08 Nov-07 Dec-07 Jan-08 Feb-08 Oct-07 Mar-08 Cold Primary Production Pump Change Aug-08 May-08 Nov-08 Dec-08 Sep-08 Jun-08 Jan-09 Feb-09 Mar-09 Apr-09 Oct-08 Jul-08 B.C. Seal – Reserves Recognition Alberta  Sask. Dec 31/05 Dec 31/06 Dec 31/07 Dec 31/08 Reserves (MMbbl) Proved Proved plus Probable Locations Assigned Reserves Proved Producing Total Proved 6 14 8 62 25 103 44 106 2.2 4.0 8.5 13.0 20.2 28.7 27.0 39.2 Proved plus Probable Land Assigned Reserves Sections (640 acres) 20 64 109 134 4 8 12 15 Note: Probable volume includes 2.4 MMbbl of thermally-enhanced oil recovery, covering approximately upper one-third of Bluesky Sand over one section of land. All other reserve volumes are for cold development. Heavy Oil Differential High demand season (Apr – Sep) Low demand season (Oct – Mar) 60 50 Lloyd Blend Differential (% of WTI Price) 40 30 20 10 0 2005 2006 2007 2008 2009 Heavy Oil Differential 60% 50% LLB Differential (% of WTI) 40% 30% 20% 10% 0% J F M 2001 2004 2007 2009 A M J 2002 2005 2008 J A S O N D 2003 2006 Average 2001-2008 Heavy Oil Differential vs. WTI 150 45 40 125 35 100 30 25 75 20 50 15 10 25 5 0 3 4 5 6 7 8 Ja n0 Ja n0 Ja n0 Ja n0 Ja n0 Ja n0 Ja n0 9 0 WTI Lloyd Differential Lloyd Differential (US$/bbl) WTI (US$/bbl) Heavy Oil Differential / WTI Relationship 40 Lloyd Differential (US$/bbl) 30 20 2005 - 2007 10 2008 - 2009 0 0 25 50 75 WTI (US$/bbl) Note: Lloyd differential shifted back one month to reflect trading sequence versus WTI cash settlement. 100 125 150 Infrastructure Development Existing Major Pipelines 2006 Pipeline Reversals Fort McMurray Kitimat Edmonton Hardisty Winnipeg Superior Approved Pipeline (Under Construction) Proposed Pipelines Calgary Chicago Guernsey Patoka Cushing Salt Lake City Los Angeles Artesia Port Arthur Nederland Heavy Oil Investment Metrics 200 Before Tax ROR (%) 150 Lloyd Area Cold Seal Cold Seal Thermal 100 50 0 30 35 40 45 50 55 60 WTI ($US) Light Oil Resource Plays   Viking Bakken / Three Forks   Mowry Shale Light Oil Resource Potential Initial Rate (Boe/d / Well) Bakken / Three Forks Viking Mowry Shale Estimated Recovery (Thousand boe /Well) Well Cost ($Million / well) Potential Net Locations Potential Recovery (Million boe) ≥ 190 ≥ 70 ~ 200 ≥ 280 ≥ 50 ~ 200 US$4.5 Cdn$1.45 US$3.9 150 - 300 200 60 42 - 84 ≥ 10 ~ 12 Total 410 - 560 64 - 106 Note: All values shown in this table represent Baytex’s internal estimates. Hedging Program Heavy Oil Differential Hedged WCS blend volume (bbl/d) Approximate equivalent raw heavy volume (bbl/d) WCS Blend price Date Contract Executed Term of Contract WTI Oil Hedged volume (bbl/d) Avg. collar floor price (US$/bbl) Avg. collar cap price (US$/bbl) Term of Contract Natural Gas 4,000 $100.00 $154.55 Calendar 2009 10,340 7,850 WTI X 67% Sept 2007 Calendar 2009 775 600 WTI X 80% Jan 2009 Apr-Aug 2009 775 600 WTI – US$10.00/bbl Jan 2009 Apr-Aug 2009 510 390 WTI – US$7.60/bbl Mar 2009 May 2009 Hedged volume (MMcf/d) Avg. collar floor price (C$/Mcf) Avg. collar cap price (C$/Mcf) Term of Contract Foreign Exchange Hedged amount (US$ million) Swap rate (CAD/USD) Term of Contract Synthetic Raw Heavy Oil Hedged raw volume (bbl/d) Hardisty Heavy raw oil price (C$/bbl) Date Contract Executed Term of Contract 4.7 $7.39 $8.39 Calendar 2009 4.7 $5.28 $6.65 Apr 2009 – Dec 2010 5.7 $5.36 $6.75 Calendar 2010 120 0.7995 Calendar 2009 24 0.8602 May – Dec 2009 120 0.8403 Calendar 2010 15 0.8696 Jan – Mar 2011 1,155 $56.08 May 2009 July – Dec 2009 1,925 $55.26 April 2009 Calendar 2010 Hedging Program - Synthetic Raw Heavy • Risk management instrument to lock raw heavy pricing • Simultaneous swap of four components – WTI, WCS differential, condensate differential and FOREX • Creates “financial synthetic” price for Hardisty Heavy crude July-Dec 2009 Blend volume (bbl/d) Raw volume (bbl/d) Hardisty Raw Heavy Oil Price (C$/bbl) 1,500 1,155 $56.08 Calendar 2010 2,500 1,925 $55.26 • Compares favorably to historic pricing for Hardisty Heavy crude Year Annual Average Raw Heavy Oil Price (C$ / bbl) 2004 2005 2006 2007 2008 2009 (Jan – May) 30.92 32.61 41.78 42.35 73.82 43.72 Financial Strength C$ Million Dec 31 2005 Dec 31 2006 Dec 31 2007 Dec 31 2008 Mar 31 2009 US$ subordinated notes Convertible debentures Bank loan and working capital Total monetary debt Cash Flow (C$ million) Debt / Cash Flow (1) (2) 210 74 210 19 178 16 220 10 227 10 140 424 227 1.9 138 367 275 1.3 250 444 286 1.6 302 532 434 1.2 325 562 392 1.4 (1,2) (2) (3) (3) As compared to revolving credit facilities of $515 million. Prior to equity issuance of $109 million on April 14, 2009. (3) Cash flow based on trailing four quarters. Total Return Performance Baytex Energy Trust S&P/TSX Composite Index S&P/TSX Capped Energy Trust Index S&P 500 400 350 300 250 200 150 100 50 Sep-03 Jan-04 May-04 Sep-04 Jan-05 May-05 Sep-05 Jan-06 May-06 Sep-06 Jan-07 May-07 Sep-07 Jan-08 May-08 Sep-08 Jan-09 May-09 Note: Total return includes capital appreciation, cash distributions and reinvestment of distributions to May 25, 2009 Source: TSX Historical Data, Bloomberg Data, and Company information Total Return Performance One Year Apr 08 – Apr 09 Two Year Apr 07 – Apr 09 Three Year Apr 06 – Apr 09 Four Year Apr 05 – Apr 09 Five Year Apr 04 – Apr 09 Since BTE Inception Baytex Energy Trust -21.8 +1.5 +3.4 +16.4 +20.2 +22.3 S&P/TSX Energy Trust Index -35.5 -11.4 -12.3 +0.9 +8.2 +10.4 S&P/TSX Composite Index -29.2 -13.6 -5.5 +3.1 +4.5 +6.5 S&P 500 (USD) -36.0 -21.7 -10.9 -4.9 -3.4 -1.1 Baytex Percentile Ranking Within Conventional Energy Trust Universe 90 90 95 95 94 94 Total return includes capital appreciation, cash distributions and reinvestment of distributions for time periods ending April 24, 2009, calculated on a compounded annual basis. Baytex Energy trust inception date was September 8, 2003. Conventional trust universe includes AET, AVN, BNE, BNP, CPG, DAY, ENT, ERF, FRU, HTE, NAE, PEY, PGF, PMT, PVE, PWT, TET, TUI, VET and ZAR. All returns measured in Canadian dollars, except S&P 500, which is in US dollars. Value Comparison Trust Average Baytex (Range) EV/2009(e) Production (C$/boe/d) EV/P+P Reserves ($/boe) $61,400 $12.49 $83,100 ($57,300 – $143,600) $17.93 ($11.27 – $25.38) (5.9x – 27.2x) (4.3x – 29.9x) EV/2009(e) DACF P/CF 2009(e) P/NAV Debt/Cash Flow 2009(e) Distribution Payout 2009(e) Oil Weighting 2009(e) 8.1x 7.3x 114% 1.7x 57% 78% 10.3x 9.8x 124% (100% – 155%) (0.1x – 2.8x) 1.7x 66% (49%– 73%) 62% (42% - 100%) Source: Canaccord Adams research dated May 19, 2009. Trust coverage group includes AET, BTE, COS, CPG, DAY, ERF, HTE, NAE, PWT, and VET. 2009 commodity assumptions: WTI oil US$45.00/bbl, NYMEX gas US$5.00/mmbtu, US$0.80/Cdn$, Lloyd Hardisty Heavy Oil differential to WTI 20%. Summary • • Desirable attributes for an energy investment regardless of legal structure Quality asset base and disciplined investment approach resulting in industry-leading capital efficiency Diversified product mix – Significant potential in both heavy and light oil resource plays – Positioned to benefit from improving heavy oil differentials • • • Conservative payout ratio and strong balance sheet Long-term market out-performance and still compelling relative valuation Contact Information Anthony W. Marino President and CEO (403) 267-0708 Erin M. Cripps Investor Relations (403) 538-3681 W. Derek Aylesworth Chief Financial Officer (403) 538-3639 Cheryl L. Arsenault Investor Relations (403) 267-0761 Baytex Energy Trust Suite 2200, Bow Valley Square II 205 – 5th Avenue S.W. Calgary, Alberta T2P 2V7 telephone: (403) 262-4282 1-800-524-5521 website: www.baytex.ab.ca