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

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.

• 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

Corporate Background

Trust Units

Trading Symbols TSX: BTE.UN / NYSE: BTE

Average Daily Volume (1) TSX: 438,000 / NYSE: 190,000

Units Outstanding (Current) 110.7 million

Market Value of Equity / Enterprise Value C$4.0 billion / C$4.5 billion

Monthly Distributions C$0.18/unit

Cash-on-Cash Yield (2) 6.0%

Cumulative Cash Distributions C$1.1 billion

6.5% Convertible Debentures

Trading Symbol TSX: BTE.DB

Principal Outstanding (Current) C$6.4 million

Conversion Price C$14.75

Maturity Date December 2010

9.15% Series A Senior Unsecured Debentures (3)

Principal Outstanding C$150 million

Maturity Date August 2016

Current Price / Yield $109.50 / 6.6%(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.

Capital Markets Information

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.

Canada - Institutional 43%US - Retail 25%

Europe - Institutional 2%

US - Institutional 11%

Canada - Retail 18%

Insiders 1.4%Ownership Breakdown:

Institutional 56%Retail 43%Insiders 1%

100%

Canada 61%U.S. 36%International 2%Insiders 1%

100%

• 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

Operating Areas

Production Split by Jurisdiction

Saskatchewan47% BC

6%

Alberta46%

US 1%

Reserves by Product (Year End 2009)

Heavy Oil74%

Light Oil15%

Gas 11%

Product Mix (6:1)Company Total = 43,500 boe/d

(Full Year Guidance 2010)

Heavy Oil63%

Gas20%

Light Oil17%

Historical Performance

2004 2005 2006 2007 2008 2009

Full Year

Guidance

2010

Production

Light oil & NGL (bbl/d) 2,172 3,842 3,735 5,483 7,595 6,937 7,400

Heavy oil (bbl/d) 22,70320,73

521,32

5 22,092 23,530 24,678 27,400

Natural gas (MMcf/d) 54.9 60.4 55.4 51.9 54.8 58.6 52.2

Total (boe/d) 34,02234,64

734,29

2 36,222 40,239 41,382 43,500

Capital Expenditures (C$ million)

E & D 95 130 133 149 185 157 235

Acquisitions (net) 186 22 - 245 265 133 -

Total 281 152 133 394 450 290 235

Operating Performance

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

(1)

Distribution History

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Payout Ratio - Net of DRIP (%) Monthly Distribution (C$)

December 31,

2003 2004 2005 2006 2007 2008 2009

Proved plus Probable

Light oil & NGL (MMbbl) 7.2 13.1 12.7 11.7 20.8 31.4 29.1

Heavy oil (MMbbl) 81.4 80.8 97.6 108.7 122.5 126.1 145.6

Natural gas (Bcf) 106.3 155.1 176.4 148.1 148.9 178.2 133.7

Total (MMboe) 106.3 119.7 140.0 145.1 168.1 187.1 197.0

Reserve Life Index (years) 8.3 9.1 11.0 11.6 12.3 12.8 12.4

Percent Oil 83% 78% 79% 83% 85% 84% 89%

Oil & Gas Reserves

Working interest reserves per NI 51-101 as evaluated by Sproule Associates Limited.

Reserves Growth

77 84101 103 116 126 129

3035

38 4352

61 68

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Proved Probable

2007 2008 2009

3-Year Average 2007-09

5-YearAverage 2005-09

Since Inception

FD&A Cost (P + P)

Excluding FDC (C$/boe) 10.90 13.11 11.63 11.89 9.72 9.90

Including FDC (C$/boe) 11.91 16.06 21.00 15.16 13.56 13.42

Recycle Ratio (P + P)

Excluding FDC 2.2 2.6 2.4 2.5 2.8 2.6

Including FDC 2.0 2.1 1.3 1.9 2.0 1.9

CAPEX as a % of FFO (1)

Exploration & Development 52% 43% 47% 47% 49% 50%

Acquisitions 86% 61% 40% 62% 43% 51%

Total 138% 104% 87% 109% 92% 101%

Production Replacement

(P+P)

Exploration & Development 121% 119% 113% 118% 124% 117%

Acquisitions 149% 114% 52% 104% 90% 96%

Total 271% 233% 165% 222% 214% 213%

Capital Program Efficiency

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

Heavy Oil Projects

AlbertaB.C.

Sask.

Seal - Heavy Oil Resource Play

• 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

Seal – Primary DevelopmentAlberta

B.C.

Sask.

6 Hz wells Q1/05

2 Hz wells Q1/06

9 Hz wells Q1/07

8 Hz wells Q3/07

10 Hz wells plus thermal pilot

Q1-Q2/08

9 Hz wells Q3-Q4/08

4 Hz wells Q1/09

11 Hz wells Q3-Q4/09

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Seal – Multi-Lateral HorizontalAlberta

B.C.

Sask.

Total Total Wells Single Two Three Four Six Eight Laterals

2004 2 2 --- --- --- --- --- 22005 4 4 --- --- --- --- --- 42006 2 2 --- --- --- --- --- 22007 17 13 4 --- --- --- --- 212008 19 1 17 1 --- --- --- 382009 17 1 1 7 3 2 3 72Total 61 23 22 8 3 2 3 139

Average IP Rate (bbl/d) 160 240 300 390 470 550Capex per Well ($millons) $1.1 $1.3 $1.5 $1.7 $1.8 $2.0Production Efficiency $6,900 $5,200 $5,000 $4,200 $3,800 $3,600($ per boe/d)

Number of Laterals

• 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

Seal – Thermal DevelopmentAlberta

B.C.

Sask.

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Cold Primary Production

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

Dec 31/05 Dec 31/06Dec

31/07Dec

31/08 Dec 31/09

Reserves (MMbbl)

Total Proved 2.2 8.5 20.2 27.0 31.2

Proved plus Probable 4.0 13.0 28.7 39.2 54.7

Locations Assigned

Reserves

Proved Producing 6 8 25 44 60

Total Proved 14 62 103 106 130

Proved plus Probable 20 64 109 134 189

Land Assigned Reserves

Sections (640 acres) 4 8 12 15 20

Seal – Reserves RecognitionAlberta

B.C.

Sask.

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.

Seal – Low Environmental ImpactAlberta

B.C.

Sask.

Fort McMurray Oil Sands Mining

Baytex SealNon-Mining Oil Sands

Development

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

AlbertaB.C.

Sask.

Lloydminster Drilling InventoryAlberta

B.C.

Sask.

• > 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

Heavy Oil Production (boe/d)

0

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Lloyd Heavy Seal

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)

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Seal ColdKerrobert SAGDLloyd Area Cold VerticalLloyd Area Cold HorizontalSeal Thermal

Heavy Oil Pricing

• 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

Heavy Oil Differential

Low demand season (Oct – Mar)High demand season (Apr – Sep)

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Heavy Oil Differential vs. WTI

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Note: Lloyd differential shifted back one month to reflect trading sequence versus WTI cash settlement .

2005 – 2007 Regression (R2 = 0.15)

2010

2008 – 2009 Regression (R2 = 0.57)

2009 Regression (R2 = 0.72)

2010 Hedges

Source: Wood Mackenzie, Global Oil Supply Tool, July 2009

Traditional Sources of Heavy Oil

0.0

0.4

0.8

1.2

1.6

Maya (Mexico) Maracaibo BasinHeavy Blends(Venezuela)

Marlim (Brazil)

Oriente (Ecuador) Grane (Norway)

Mil

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2008 Actual Production 2015 Production Forecast

Source: Macquarie Equities Research, January 2010 (based on Canadian Association of Petroleum Producers forecasts 2006-2009)

Projected Canadian Oil Sands Production

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May 2006 June 2007 June 2008 December 2008 June 2009

2006 Forecast

2009 Forecast

Infrastructure Development

Fort McMurray

Kitimat

EdmontonHardisty

Salt Lake City

Calgary Superior

Los AngelesArtesia

Guernsey

NederlandPort Arthur

Winnipeg

Patoka

Chicago

Existing Major Pipelines

2006 Pipeline Reversals

Approved Pipeline (Under Construction)

Proposed Pipelines

Cushing

Pipeline Capacity vs. Crude Production

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.

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Western Canadian Refiners

ExpressTMPL

PADD IV

Enbridge

Keystone

Keystone XL

AB Clipper

Supply from Operating and In Construction Projects

Supply from Production Growth Forecast

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

Mid-Continent Refining Margins

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Maya Coking (USGC)

Brent Crking

Bonny Lt Crking

WTI Cracking

Forcados Cracking

Basrah Cracking

Arab Lt. Cracking

Arab Hvy Coking

Lloydminster Coking

Canadian Heavy Oil Supply-Demand Outlook

0

0.5

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2008 2009 2010 2011 2012 2013 2014 2015

Mil

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Canadian Heavy Oil Production Refinery Demand for Canadian Heavy Oil

Source: Credit Suisse, based on June 2009 CAPP Crude Oil Forecast, “Growth Case”

Light Oil Projects

Light Oil Resource Plays

Bakken / Three Forks

Viking

Light Oil Resource Potential

Initial Rate

(Boe/d / well)

Estimated

Recovery

(Mboe / Well)

Well Cost

($Million / well)

Potential Net

Locations

Potential

CAPEX

(C$ Billion)

Potential

Recovery

(MMboe)

Bakken /

Three Forks 300 275 US$4.2 150 - 300 0.66 – 1.32 41 - 82

Viking 75 65 C$1.3 260 0.34 17

Total 410 - 560 1.0 – 1.7 58 - 99

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

Light Oil Investment Metrics

Assumptions: Cdn dollar = US $0.95 No inflation of oil prices, capital costs or operating costs.

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Viking - Multi-Lateral

Viking - Multi-Stage Frac

Bakken-Three Forks

Hedging

Hedge Coverage

Full-Year Full-YearQ1 2010 Q2 2010 Q3 2010 Q4 2010 2010 2011

Crude Oil

% of Crude Oil Volumes Hedged Fixed Price (average US$77.92/bbl) 25% 34% 34% 31% 31% 0% Costless Collars (average floor of US$71.67/bbl, average ceiling of US$92.97/bbl) 11% 11% 11% 11% 11% 0%

37% 45% 45% 43% 43% 0%Heavy Oil Differentials

% of Heavy Oil Volumes Hedged 58% 63% 54% 47% 56% 0%Equivalent Fixed Differential to WTI (US$/bbl) 12.79 13.03 13.49 13.94 13.31 -

Equivalent Percent Differential, % of WTI 16.3% 14.9% 15.2% 15.6% 15.5% -

(equivalent differentials based off 2010 price of US$86.03/bbl)

Natural Gas

% of Natural Gas Volumes Hedged Costless Collars ( Floor-Ceiling: 2010 C$5.32/mcf - C$6.71/mcf; 2011 C$5.80/mcf - C$7.49/mcf) 21% 21% 22% 24% 22% 6%

Fixed Price 33% 15% 14% 15% 19% 8% Sold Calls ( Average Strike: US$6.25/mmbtu; Avereage Premium: US$0.64) 0% 0% 0% 0% 0% 5%

Total Natural Gas 54% 36% 36% 39% 41% 19%

Average prices for fixed price contracts (C$/mcf): 5.61$ 5.74$ 5.84$ 5.84$ 5.76$ 5.21$

Foreign Exchange

% of Foreign Exchange Hedged 33% 35% 35% 35% 35% 16%Hedged Amount (US$ millions) 54 57 57 57 225 114Average Swap Rate (USD/CAD) 0.8813 0.8899 0.8899 0.8899 0.8878 0.9274

Note: percentage of volumes hedged reflects Baytex volumes (company production of 43,500 boe/d), net of royalties (i.e. hedgeable volumes).

Interest Rate Hedge Positions

Interest Rate (for Sr Unsecured Debentures)

Hedged Amount (C$ million) 150

Swap Type Receive-Fixed

Floating Rate 3-month LIBOR + 787.5 bps

Fixed Rate 915 bps

Term of Contract Oct 2009 - Sept 2011

Interest Rate (for US$ Bank Line Draw)

Hedged Amount (US$ million) 90 90

Swap Type Forward-Starting Pay-Fixed Forward-Starting Pay-Fixed

Floating Rate 3-month LIBOR 3-month LIBOR

Fixed Rate 4.055% 4.385%

Term of Contract Oct 2011 - Sep 2014 Oct 2012 - Sep 2014

Balance Sheet

Dec 31 2004

Dec 31 2005

Dec 31 2006

Dec 31 2007

Dec 312008

Dec 31

2009

US Subordinated Notes 217 210 210 178 220 -

Cdn Sr Unsecured Debentures - - - - - 150

Convertible Debentures - 74 19 16 10 8

Bank Loan and Working Capital (C$ draws) 196 140 138 250 302 128

Bank Loan (US$ draws) - - - - - 188

Total Monetary Debt 413 424 367 444 532 474

Funds From Operations 136 227 275 286 434 332

Cash Distributions 113 122 158 174 244 138

C$ Million

Financial Strength

(1) Translated to Canadian dollars using the December 31, 2009 USD/CAD noon rate of 0.9555.

(1)

Dec 31 2004

Dec 31 2005

Dec 31 2006

Dec 31 2007

Dec 312008

Dec 312009

Credit Facility (C$ Millions)

Approved credit facility 250 250 300 370 485 515

Bank line undrawn 54 110 162 120 183 199

Debt to EBITDA 2.6 1.5 1.2 1.4 1.0 1.3

Debt to Funds From Operations 3.0 1.9 1.3 1.6 1.2 1.4

Interest Coverage Ratio 8.4 8.6 8.8 9.1 16.6 11.1

Debt / Reserves ($/boe)

Proved 4.89 4.18 3.58 3.83 4.24 3.67

Proved + Probable 3.45 3.03 2.53 2.64 2.85 2.41

Debt / Enterprise Value 33% 26% 18% 22% 27% 13%

Credit Metrics

Financial Projections

2010E Funds From Operations (C$ Millions)

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.

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.

10% 15% 20%

$70 $398 $375 $351

$80 $473 $446 $419

$90 $548 $518 $488

Heavy Oil Differential (% of WTI)

WTI (US$/bbl)

$483Strip

Strip

10% 15% 20%

$70 1.3x 1.4x 1.6x

$80 0.9x 1.1x 1.2x

$90 0.7x 0.8x 0.9x

Heavy Oil Differential (% of WTI)

WTI (US$/bbl)

0.9x

2010E Debt to Funds From Operations

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.

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.

Strip

Strip

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.

2010E Surplus Cash Flow

10% 15% 20%

Surplus Cash Flow (C$ Millions)Funds From Operations 520 479 450E & D CAPEX (235) (235) (235)Free Cash Flow 285 244 215Distributions (net of DRIP) (203) (203) (203)Surplus Cash Flow 82 41 12

Funds From Operations per Unit 4.69 4.31 4.05Cash Distributions per Unit 2.16 2.16 2.16

Payout Ratio (net of DRIP)Basic 40% 42% 45%Total 84% 91% 97%

YE 2010 Total Debt (C$ Millions) 404 432 460Debt to Funds From Operations Ratio 0.8x 0.9x 1.0x

Heavy Oil Differential (% of WTI)

Notes:

(1) Assumes average 2010 production of 43,500 boe/d.(2) Funds From Operations sensitivities based on comparison to March 24, 2010 strip. Strip prices are WTI = US$82.06/bbl, NYMEX price =US$4.50/mmbtu, average FX = US$0.98/Cdn$, and Heavy Oil Differential = 14% of WTI.(3) FX sensitivity does not take into account “natural hedge” created by correlation between WTI and USD .

2010E Funds From Operations Sensitivities

With Current WithoutHedges Hedges

WTI +/- US$1.00/bbl 7.6 8.9

Natural Gas +/- US$0.167/mmbtu 2.6 3.2

Heavy Oil Differential +/- 1% 5.3 9.6

FX Rate +/- C$0.01/US$ 5.9 8.8

Funds From Operations Impact (C$ Millions)

Relative Performance / Valuation

Total Return Performance

Note: Total return includes capital appreciation, cash distributions and reinvestment of distributions to April 6, 2010Source: TSX Historical Data, Bloomberg Data, and Company information

0

100

200

300

400

500

600

700

800

Se

p-03

Jan-04

May

-04

Se

p-04

Jan-05

May

-05

Se

p-05

Jan-06

May

-06

Se

p-06

Jan-07

May

-07

Se

p-07

Jan-08

May

-08

Se

p-08

Jan-09

May

-09

Se

p-09

Jan-10

Baytex Energy Trust S&P/TSX Capped Energy Trust Index

S&P/TSX Composite Index S&P 500

Value Comparison

Baytex

Peer Group Average

(Range)

EV/Production (C$/boe/d)

$98,000

$139,700($66,500 – $179,000)

EV/P+P Reserves (C$/boe)

$25.96 $37.43($25.96 – $72.04)

P/NAV (10% dcf)

1.8x 1.9x(1.7x – 2.5x)

EV/DACF 2010(e)

8.7x

9.4x(7.1x – 12.9x)

Debt/Cash Flow 2010(e)

1.0x

1.3x(-0.5x – 1.9x)

Oil Weighting 78% 86%

(78% – 98%)

Source: Peters & Co. research as at April 1, 2010. Peer group represents Peters & Co. oil weighted producers comparative and includes Baytex, BlackPearl, Crescent Point, Emerge, Legacy, PetroBakken and Wild Stream. Peer group average based on enterprise value weighting.

2010 Commodity assumptions: WTI oil US$80.69/bbl, AECO gas C$4.24/mcf, US$0.97/Cdn$, Heavy Oil differential to Edmonton Par 14%.

Baytex

Baytex

Baytex

Anthony W. MarinoPresident and CEO

(403) 267-0708

W. Derek AylesworthChief Financial Officer

(403) 538-3639

Cheryl ArsenaultInvestor Relations

(403) 267-0761

Baytex Energy TrustSuite 2200, Bow Valley Square II

205 – 5th Avenue S.W.Calgary, Alberta T2P 2V7Telephone: (403) 269-4282

1-800-524-5521Website: www.baytex.ab.ca

Contact Information

Brian EctorDirector of Investor Relations

(403) 267-0702