IPAA Oil & Gas Investment Symposium Corporate Presentation New York, New York April 14, 2010

1. IPAA Oil & Gas Investment Symposium Corporate Presentation New York, New York April 14, 2010 Anthony W. Marino, President and Chief Executive Officer Brian Ector, Director of Investor Relations

2. 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; our Seal heavy oil resource play, including our assessment of the cyclic steam pilot project, the viability and economics of long-term commercial development using primary (cold) and thermal 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, production efficiency ratios and steam-oil ratios; our Lloydminster heavy oil property, including drilling inventory, efficiency ratios, netbacks and recycle ratios; rates of return for our heavy oil projects; oil and gas prices and differentials between light, medium and heavy oil prices; international heavy oil production; Canadian oil sands production; proposed pipeline infrastructure development; the supply of crude oil from Western Canada; pipeline capacity for Western Canadian crude oil; the supply and demand outlook for Canadian heavy oil; our Bakken/Three Forks and Viking light oil resources plays, including initial production rates, estimated recoverable reserves, drilling and completion costs per well, the number of potential drilling locations, potential total capital expenditures and rates of return; our hedging program; our debt to EBITDA, debt to funds from operations, interest coverage, debt to reserves and debt to enterprise value ratios; our 2010 funds from operations; our 2010 year-end debt to funds from operations ratio; our 2010 surplus cash flow, payout ratio and debt to funds from operations ratio; the sensitivity of our 2010 funds from operations to changes in West Texas Intermediate oil prices, natural gas prices, heavy oil differentials and Canada-United States foreign exchange rates; 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: petroleum 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: fluctuations in market prices for petroleum and natural gas; fluctuations in foreign exchange or interest rates; general economic, market and business conditions; stock market volatility and market valuations; changes in income tax laws; industry capacity; geological, technical, drilling and processing problems and other difficulties in producing petroleum and natural gas reserves; uncertainties associated with estimating petroleum and natural gas reserves; liabilities inherent in oil and natural gas operations; competition for, among other things, capital, acquisitions of reserves, undeveloped lands and skilled personnel; risks associated with oil and gas operations; changes in royalty rates and incentive programs relating to the oil and gas industry; changes in environmental and other regulations; incorrect assessments of the value of acquisitions; 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, 2009, 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.

3. Sustainable model: Income return + organic growth + free cash flow Sector-leading capital efficiency Technical focus Long-term, low-cost development inventory Significant potential in both heavy and light oil resource plays High oil weighting, but diversified within oil complex Conservative payout ratio and strong balance sheet Long-term market out-performance Summary

4. Corporate Background

5. Capital Markets Information (1) Average daily trading volumes based on the last 20 trading days through March 31, 2010. (2)The cash-on-cash yield is calculated by dividing the annualized distribution of C$2.16 by the closing price of Baytex units of C$36.06 on the TSX on April 6, 2010. (3)The US$180 million 9.625% Senior Subordinated Notes due July 15, 2010 were redeemed on September 25, 2009.

6. Ownership Breakdown Baytex shareholder base, estimated on March 1, 2010. Sources: TSX Connect, Credit Suisse and Baytex internal data. Officers’ direct ownership totals more than six times total annual salary.

7. 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 Inc. created from Baytex Energy Ltd. BTE listed on NYSE in March 2006 Highest total return among 16 oil and gas trusts since Baytex Energy Trust inception Probable conversion back to corporation at end of 2010 Plan to execute growth-and-income model Desirable attributes for an energy investment regardless of legal structure Corporate History

8. Operating Areas

9. Historical Performance

10. Operating Performance (1) (1) Excluding 2,100 bbl/d of SAGD production purchased on Oct 1/05 and sold on Dec 31/05.

11. Distribution History

12. Oil & Gas Reserves Working interest reserves per NI 51-101 as evaluated by Sproule Associates Limited.

13. Reserves Growth

14. Capital Program Efficiency (1) Funds From Operations (“FFO”) includes realized hedging gains / losses.

15. Heavy Oil Projects

16. B.C. Alberta Sask. Seal - Heavy Oil Resource Play 

17. 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 = $1.5 million/well (triple lateral) IP  300 bbl/d per well (triple lateral) P+P reserves = 405 Mbbl/well (triple lateral) F&D cost = $3.70 per bbl (triple lateral) OPEX = $2.86 per bbl (2009 actual) Recovery factor: 5-7% OOIP B.C. Alberta Sask. Seal – Primary Development  11 Hz wells Q3-Q4/09 4 Hz wells Q1/09 9 Hz wells Q3-Q4/08 10 Hz wells plus thermal pilot Q1-Q2/08 8 Hz wells Q3/07 9 Hz wells Q1/07 6 Hz wells Q1/05 2 Hz wells Q1/06

18. B.C. Alberta Sask. Seal – Multi-Lateral Horizontal 

19. Modular development Readily executable 10-well size Traditional oil and gas area CAPEX = $31 million Recovery per 10-well module (Baytex Estimates) Recovery factor ≈30% based on numerical reservoir simulation Validated by field pilot Oil rate = 1,700 bbl/d (peak year) / 2,200 bbl/d (peak month) EUR = 3.8 MMbbl Projected OPEX using $6.50 per mcf gas cost <$10 per bbl initially $14 per bbl over project life First module planned by end of 2011 B.C. Alberta Sask. Seal – Thermal Development  Incremental SOR (deducting cold primary) = 1.3 BS/BO Gross SOR (without deducting cold primary) = 0.7 BS/BO Fuel Requirement = 0.44 MCF/BS

20. B.C. Alberta Sask. Seal – Reserves Recognition  Note: Probable volume for 2009 includes 8.2 MMbbl of thermally-enhanced oil recovery covering one section of land. All other reserve volumes are for cold development.

21. B.C. Alberta Sask. Seal – Low Environmental Impact  Fort McMurray Oil Sands Mining Baytex Seal Non-Mining Oil Sands Development

22. B.C. Alberta Sask. Lloydminster Heavy Oil  • 2009 Production = 20,800 boe/d (50% of total Baytex volumes) • Oil Gravity = 11 to 18 °API • YE 2009 Reserves (2P) = 91 mmboe (46% of total Baytex reserves) • Reserve Life Index (2P) = 12.2 years • Land Position = 495,000 net acres • 2009 Drilling: 70 gross (62.3 net) wells 63 recompletions 96% success rate • 2010 E&D CAPEX: ≈ $90 million • 2010 Drilling: ≈ 70 gross (63 net) wells ≈ 70 recompletions

23. B.C. Alberta Sask. Lloydminster Drilling Inventory  • > 5 year drilling inventory • Drilling inventory has increased by 75% over the past five years • Development includes vertical / horizontal / thermal (SAGD) • Efficiency ratios (half cycle): - $12,100 per boe/d - $10.10/boe based on 2P reserves • 2010E netback of ≈ $38/boe (based on forward strip) generates a recycle ratio of 3.8x

24. Heavy Oil Investment Metrics Assumptions: Lloyd Blend differential to WTI = 15% Condensate discount to WTI = US $2.50 per bbl Gas cost for thermal project = Cdn $6.50 per mcf Cdn dollar = US $0.96 Flat prices (no escalation of oil price or gas cost)

25. Heavy Oil Pricing

26. Market data suggest continued low differentials Fundamental drivers suggest continued low differentials Reduced supply from traditional sources / Canadian oil sands growth lags forecasts Excess pipeline capacity now available Heavy oil refining has highest margins relative to other crudes Forecasted demand-supply imbalance for heavy oil in North America WCS differential ≈ 12.4% of WTI price (January – April 2010) Majority of Baytex’s differential exposure is hedged for 2010 Heavy Oil Differential

27. High demand season (Apr – Sep) Low demand season (Oct – Mar) Heavy Oil Differential

28. Heavy Oil Differential

29. Heavy Oil Differential vs. WTI

30. 2005 – 2007 Regression (R2 = 0.15) 2008 – 2009 Regression (R2 = 0.57) 2010 Hedges 2010 2009 Regression (R2 = 0.72) Heavy Oil Differential / WTI Relationship Note: Lloyd differential shifted back one month to reflect trading sequence versus WTI cash settlement.

31. 1.6 1.2 Million Barrels per Day 0.8 0.4 0.0 Maya (Mexico) Maracaibo Basin Marlim (Brazil) Oriente (Ecuador) Grane (Norway) Heavy Blends 2008 Actual Production 2015 Production Forecast (Venezuela) Traditional Sources of Heavy Oil Source: Wood Mackenzie, Global Oil Supply Tool, July 2009

32. Projected Canadian Oil Sands Production Source: Macquarie Equities Research, January 2010 (based on Canadian Association of Petroleum Producers forecasts 2006-2009)

33. Infrastructure Development Existing Major Pipelines 2006 Pipeline Reversals Approved Pipeline (Under Construction) Proposed Pipelines Fort McMurray Kitimat Edmonton Hardisty Winnipeg Superior Calgary Chicago Guernsey Patoka Cushing Salt Lake City Los Angeles Artesia Nederland Port Arthur

34. Pipeline Capacity vs. Crude Production Supply from Operating and In Construction Projects Supply from Production Growth Forecast Source: Canadian Association of Petroleum Producers report “Crude Oil Forecast, Markets and Pipeline Expansions”, June 2009. Black lines represent aggregate Western Canadian crude supply including diluent volumes.

35. Mid-Continent Refining Margins Source: Peters & Co. research, based on data from Bloomberg. Note: Mayan coking margins are presented for the U.S. Gulf Coast.

36. Canadian Heavy Oil Supply-Demand Outlook 2.5 2 1.5 Million Barrels per Day 1 0.5 0 2008 2009 2010 2011 2012 2013 2014 2015 Canadian Heavy Oil Production Refinery Demand for Canadian Heavy Oil Source: Credit Suisse, based on June 2009 CAPP Crude Oil Forecast, “Growth Case”

37. Light Oil Projects

38. Light Oil Resource Plays  Viking  Bakken / Three Forks 

39. Light Oil Resource Potential Notes: All values shown in this table represent Baytex’s internal estimates. C$ = US$0.95

40. Light Oil Investment Metrics Assumptions: Cdn dollar = US $0.95 No inflation of oil prices, capital costs or operating costs.

41. Hedging

42. Hedge Coverage

43. Interest Rate Hedge Positions

44. Balance Sheet

45. Financial Strength C$ Million (1) (1) Translated to Canadian dollars using the December 31, 2009 USD/CAD noon rate of 0.9555.

46. Credit Metrics

47. Financial Projections

48. 2010E Funds From Operations (C$ Millions) Strip Strip $483 Funds From Operations using April 6, 2010 strip = C$483 million. Strip prices are WTI = US$86.03/bbl, NYMEX = US$4.62/mmbtu, FX = US$0.997/C$ and Heavy Oil Differential = 14.5% of WTI. Notes: (1) Assumes average 2010 production of 43,500 boe/d. (2) Assumes average NYMEX = US$4.50/mmbtu and average FX = US$0.98/C$. (3) BTE 2010E cash requirements total $438 million: E&D CAPEX = $235 million and cash distributions net of distribution reinvestment plan = $203 million.

49. 2010E Debt to Funds From Operations Strip 0.9x Strip Total debt to Funds From Operations ≈ 0.9x using April 6, 2010 strip. Strip prices are WTI = US$86.03/bbl, NYMEX = US$4.62/mmbtu, FX = US$0.997/C$ and Heavy Oil Differential = 14.5% of WTI. Notes: (1) Assumes average 2010 production of 43,500 boe/d. (2) Assumes average NYMEX = US$4.50/mmbtu and average FX = US$0.98/C$. (3) Debt to Funds From Operations ratio is based on forecast year-end 2010 total debt and 2010E Funds From Operations.

50. 2010E Surplus Cash Flow • Notes: • (1) Assumes average 2010 production of 43,500 boe/d. • (2) Table based on April 6, 2010 strip. Strip prices are WTI = US$86.03/bbl, NYMEX price =US$4.62/mmbtu, average FX = US$0.997/Cdn$. • (3) Payout Ratios are calculated net of distribution reinvestment program (“DRIP”). DRIP proceeds typically ≈ 15% of distributions. • (4) Basic Payout Ratio = Cash distributions / Funds From Operations. • (5) Total Payout Ratio = Cash distributions + capital expenditures / Funds From Operations. • (6) Debt to Funds From Operations Ratio is based off forecast year-end 2010 total debt and 2010E Funds From Operations.