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
0%
20%
40%
60%
80%
100%
120%O
ct-0
3
Jan
-04
Ap
r-04
Jul-
04
Oct
-04
Jan
-05
Ap
r-05
Jul-
05
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-05
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-06
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06
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-06
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-07
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r-07
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-07
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-08
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-08
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-09
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r-09
Jul-
09
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-09
Jan
-10
Pay
ou
t R
atio
- N
et o
f D
RIP
(%
)
0.00
0.05
0.10
0.15
0.20
0.25
0.30
Mo
nth
ly D
istr
ibu
tio
n (
C$)
Payout Ratio - Net of DRIP (%) Monthly Distribution (C$)
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
0
50
100
150
200
2003 2004 2005 2006 2007 2008 2009Oil-
Eq
uiv
ale
nt
Re
se
rve
s (
MM
bo
e)
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 = $2.86 per bbl (2009 actual)
- Recovery factor: 5-7% OOIP
Seal – Primary DevelopmentAlberta
B.C.
Sask.
6 Hz wells Q1/05
2 Hz wells Q1/06
9 Hz wells Q1/07
8 Hz wells Q3/07
10 Hz wells plus thermal pilot
Q1-Q2/08
9 Hz wells Q3-Q4/08
4 Hz wells Q1/09
11 Hz wells Q3-Q4/09
0
1000
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7000
8000
Ja
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l / d
Seal – Multi-Lateral HorizontalAlberta
B.C.
Sask.
Total Total Wells Single Two Three Four Six Eight Laterals
2004 2 2 --- --- --- --- --- 22005 4 4 --- --- --- --- --- 42006 2 2 --- --- --- --- --- 22007 17 13 4 --- --- --- --- 212008 19 1 17 1 --- --- --- 382009 17 1 1 7 3 2 3 72Total 61 23 22 8 3 2 3 139
Average IP Rate (bbl/d) 160 240 300 390 470 550Capex per Well ($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.
0
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Bar
rels
of
Oil
Per
Day
Actual Cold Projected Cold Post-Steam
Inje
ct
Ste
am /
So
ak
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
5,000
10,000
15,000
20,000
25,000
30,000
2005 2006 2007 2008 2009
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 $0.96 Flat prices (no escalation of oil price or gas cost)
0
100
200
300
400
500
30 40 50 60 70 80 90 100
WTI (US$)
Bef
ore
T
ax
RO
R (
%)
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)
0
10
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60
2005 2006 2007 2008 2009 2010
Llo
yd B
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iffe
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(% o
f W
TI
Pri
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Heavy Oil Differential
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iffe
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l (%
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I)
2001 2002 2003 2004
2005 2006 2007 Average 2001-20072008 2009 2010 2010 Forward Curve
Heavy Oil Differential vs. WTI
0
25
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75
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150
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3
Jan-0
4
Jan-0
5
Jan-0
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Jan-0
7
Jan-0
8
Jan-0
9
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0
WT
I (U
S$
/bb
l)
-
5
10
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25
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35
40
45
Llo
yd
Dif
fere
nti
al (
US
$/b
bl)
WTI Forward WTILloyd Differential Forward Lloyd Differential
0
10
20
30
40
0 25 50 75 100 125 150
WTI (US$/bbl)
Llo
yd D
iffe
ren
tial
(U
S$/
bb
l)Heavy Oil Differential / WTI Relationship
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
lio
n B
arr
els
pe
r D
ay
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
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Oil
San
ds
Pro
du
ctio
n
(mil
lio
n b
bl/
day
)
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.
0
1000
2000
3000
4000
5000
6000
2009 2011 2013 2015 2017 2019 2021 2023 2025
Th
ou
san
d o
f B
arre
ls P
er D
ay
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
(10)
-
10
20
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n-1
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Re
fin
ing
Ma
rgin
(U
S$
/bb
l)
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
1
1.5
2
2.5
2008 2009 2010 2011 2012 2013 2014 2015
Mil
lio
n B
arr
els
pe
r D
ay
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 $0.95 No inflation of oil prices, capital costs or operating costs.
0
20
40
60
80
100
40 50 60 70 80 90 100
WTI (US$)
Bef
ore
T
ax
RO
R (
%)
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