This is the Presentation Title

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
Summary

• 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

4
Corporate Background
5
Capital Markets Information
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 C4.0 billion / C4.5 billion
Monthly Distributions C0.18/unit
Cash-on-Cash Yield (2) 6.0
Cumulative Cash Distributions C1.1 billion
6.5 Convertible Debentures
Trading Symbol TSX BTE.DB
Principal Outstanding (Current) C6.4 million
Conversion Price C14.75
Maturity Date December 2010
9.15 Series A Senior Unsecured Debentures (3)
Principal Outstanding C150 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 C2.16 by the
closing price of Baytex units of C36.06 on the
TSX on April 6, 2010. (3) The US180 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
Corporate History

• Publicly-traded EP corporation from 1993-2003
• One of only six independent EP 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

8
Operating Areas
9
Historical Performance
10
Operating 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) 22,703 20,735 21,325 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) 34,022 34,647 34,292 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
(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
December 31, December 31, December 31, December 31, December 31, December 31, 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
Working interest reserves per NI 51-101 as
evaluated by Sproule Associates Limited.
13
Reserves Growth
14
Capital Program Efficiency
2007 2008 2009 3-Year Average 2007-09 5-YearAverage 2005-09 Since Inception
FDA 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 (PP)
Exploration Development 121 119 113 118 124 117
Acquisitions 149 114 52 104 90 96
Total 271 233 165 222 214 213
(1) Funds From Operations (FFO) includes
realized hedging gains / losses.
15
Heavy Oil Projects
16
Seal - Heavy Oil Resource Play
?
17
Seal Primary Development
?

• 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)
• PP reserves 405 Mbbl/well (triple lateral)
• FD cost 3.70 per bbl (triple lateral)
• OPEX 2.86 per bbl (2009 actual)
• Recovery factor 5-7 OOIP

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
Seal Multi-Lateral Horizontal
?
19
Seal Thermal Development
?

• 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
• lt10 per bbl initially
• 14 per bbl over project life
• First module planned by end of 2011

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
Seal Reserves Recognition
?
Dec 31/05 Dec 31/06 Dec 31/07 Dec 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
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
Seal Low Environmental Impact
?
Fort McMurray Oil Sands Mining
Baytex Seal Non-Mining Oil Sands Development
22
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 ED CAPEX 90 million
• 2010 Drilling 70 gross (63 net) wells
• 70 recompletions

23
Lloydminster Drilling Inventory
?

• gt 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
Heavy Oil Differential

• 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 Baytexs differential exposure is
  hedged for 2010

27
Heavy Oil Differential
28
Heavy Oil Differential
29
Heavy Oil Differential vs. WTI
30
Heavy Oil Differential / WTI Relationship
Note Lloyd differential shifted back one month
to reflect trading sequence versus WTI cash
settlement.
31
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
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 US4.2 150 - 300 0.66 1.32 41 - 82
Viking 75 65 C1.3 260 0.34 17
Total 410 - 560 1.0 1.7 58 - 99
Notes All values shown in this table represent
Baytexs internal estimates. C
US0.95
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
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
44
Balance Sheet
45
Financial Strength
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
(1)
(1) Translated to Canadian dollars using the
December 31, 2009 USD/CAD noon rate of 0.9555.
46
Credit Metrics
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
47
Financial Projections
48
2010E Funds From Operations (C Millions)
Strip
483
Strip
Funds From Operations using April 6, 2010 strip
C483 million. Strip prices are WTI
US86.03/bbl, NYMEX US4.62/mmbtu, FX
US0.997/C and Heavy Oil Differential 14.5 of
WTI.
Notes (1) Assumes average 2010 production of
43,500 boe/d. (2) Assumes average NYMEX
US4.50/mmbtu and average FX US0.98/C. (3)
BTE 2010E cash requirements total 438 million
ED 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
US86.03/bbl, NYMEX US4.62/mmbtu, FX
US0.997/C and Heavy Oil Differential 14.5 of
WTI.
Notes (1) Assumes average 2010 production of
43,500 boe/d. (2) Assumes average NYMEX
US4.50/mmbtu and average FX US0.98/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 US86.03/bbl, NYMEX price
  US4.62/mmbtu, average FX US0.997/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.

51
2010E Funds From Operations Sensitivities
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 US82.06/bbl,
NYMEX price US4.50/mmbtu, average FX
US0.98/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 .
52
Relative Performance / Valuation
53
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
54
Value Comparison
Baytex Peer Group Average (Range)
EV/Production (C/boe/d) 98,000 139,700(66,500 179,000)
EV/PP 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
US80.69/bbl, AECO gas C4.24/mcf, US0.97/Cdn,
Heavy Oil differential to Edmonton Par 14.
55
Contact Information
Baytex Baytex Baytex
Anthony W. Marino President and CEO [phone]
W. Derek Aylesworth Chief Financial Officer (403)
538-3639
Cheryl Arsenault Investor Relations [phone]
Brian Ector Director of Investor Relations (403)
267-0702
Baytex Energy Trust Suite 2200, Bow Valley Square
II 205 5th Avenue S.W. Calgary, Alberta T2P
2V7 Telephone [phone] Websi
te www.baytex.ab.ca