Transcript This is the Presentation Title

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.
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
Corporate Background
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
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
(1)
(2)
(3)
(3)
Principal Outstanding
C$150 million
Maturity Date
August 2016
Current Price / Yield
$109.50 / 6.6%
Average daily trading volumes based on the last 20 trading days through March 31, 2010.
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.
The US$180 million 9.625% Senior Subordinated Notes due July 15, 2010 were redeemed on September 25, 2009.
Ownership Breakdown
Europe - Institutional 2%
Insiders 1.4%
US - Retail 25%
Canada - Institutional 43%
Canada - Retail 18%
US - Institutional 11%
Ownership Breakdown:
Institutional
Retail
Insiders
56%
43%
1%
100%
Canada
U.S.
International
Insiders
61%
36%
2%
1%
100%
Baytex shareholder base, estimated on March 1, 2010. Sources: TSX Connect, Credit Suisse and Baytex internal data.
Officers’ direct ownership totals more than six times total annual salary.
Corporate History
•
Publicly-traded E&P corporation from 1993-2003
– One of only six independent E&P names from 1993 that are still traded on TSX
– Heavy oil emphasis began in 1997
•
Converted to income trust in September 2003
– Baytex Energy Trust and Crew Energy Inc. created from Baytex Energy Ltd.
– BTE listed on NYSE in March 2006
– Highest total return among 16 oil and gas trusts since Baytex Energy Trust inception
•
Probable conversion back to corporation at end of 2010
– Plan to execute growth-and-income model
•
Desirable attributes for an energy investment regardless of legal structure
Operating Areas
Product Mix (6:1)
Company Total = 43,500 boe/d
(Full Year Guidance 2010)
Gas
20%
Heavy Oil
63%
Light Oil
17%
Reserves by Product (Year End 2009)
Gas
11%
Heavy Oil
74%
Light Oil
15%
Production Split by Jurisdiction
US 1%
Saskatchewan
47%
BC
6%
Alberta
46%
Historical Performance
Operating Performance
2004
Full Year
Guidance
2010
2005
2006
2007
2008
2009
2,172
3,842
3,735
5,483
7,595
6,937
7,400
22,703
20,735
21,325
22,092
23,530
24,678
27,400
54.9
60.4
55.4
51.9
54.8
58.6
52.2
34,022
34,647
34,292
36,222
40,239
41,382
43,500
95
130
133
149
185
157
235
Acquisitions (net)
186
22
-
245
265
133
-
Total
281
152
133
394
450
290
235
Production
Light oil & NGL (bbl/d)
Heavy oil (bbl/d)
Natural gas (MMcf/d)
Total (boe/d)
(1)
Capital Expenditures
(C$ million)
E&D
(1)
Excluding 2,100 bbl/d of SAGD production purchased on Oct 1/05 and sold on Dec 31/05.
0.30
100%
0.25
80%
0.20
60%
0.15
40%
0.10
20%
0.05
0%
0.00
Jul-09
Oct-09
Jan-10
Jul-08
Oct-08
Jan-09
Apr-09
Jul-07
Oct-07
Jan-08
Apr-08
Apr-06
Jul-06
Oct-06
Jan-07
Apr-07
Apr-05
Jul-05
Oct-05
Jan-06
Payout Ratio - Net of DRIP (%)
Monthly Distribution (C$)
120%
Apr-04
Jul-04
Oct-04
Jan-05
Oct-03
Jan-04
Payout Ratio - Net of DRIP (%)
Distribution History
Monthly Distribution (C$)
Oil & Gas Reserves
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
8.3
9.1
11.0
11.6
12.3
12.8
12.4
83%
78%
79%
83%
85%
84%
89%
Reserve Life Index (years)
Percent Oil
Working interest reserves per NI 51-101 as evaluated by Sproule Associates Limited.
Reserves Growth
Oil-Equivalent Reserves (MMboe)
Proved
Probable
200
150
50
68
116
126
129
2007
2008
2009
52
38
100
61
30
43
35
77
84
2003
2004
101
103
2005
2006
0
Capital Program Efficiency
2007
2008
2009
3-Year
Average
2007-09
5-Year
Average
2005-09
Since
Inception
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
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
Exploration & Development
52%
43%
47%
47%
49%
50%
Acquisitions
86%
61%
40%
62%
43%
51%
138%
104%
87%
109%
92%
101%
Exploration & Development
121%
119%
113%
118%
124%
117%
Acquisitions
149%
114%
52%
104%
90%
96%
Total
271%
233%
165%
222%
214%
213%
FD&A Cost (P + P)
Recycle Ratio (P + P)
CAPEX as a % of FFO (1)
Total
Production Replacement (P+P)
(1)
Funds From Operations (“FFO”) includes realized hedging gains / losses.
Heavy Oil Projects
B.C.
Alberta
Seal - Heavy Oil Resource Play

Sask.
B.C.
Alberta
Seal – Primary Development
•
Sask.

67,000 acres (105 sections) of 100% land
8000
7000
6000
IP  300 bbl/d per well (triple lateral)
3000
P+P reserves = 405 Mbbl/well (triple
lateral)
2000
6 Hz wells
Q1/05
2 Hz wells
Q1/06
1000
Dec-09
Jul-09
Oct-09
Apr-09
Jan-09
Oct-08
Jul-08
Apr-08
Jan-08
Oct-07
Jul-07
Apr-07
Jan-07
Oct-06
Jul-06
0
Apr-06
Recovery factor: 5-7% OOIP
9 Hz wells
Q1/07
Jan-06
OPEX = $2.86 per bbl (2009 actual)
8 Hz wells
Q3/07
Oct-05
F&D cost = $3.70 per bbl (triple lateral)
4000
Jul-05
-
CAPEX = $1.5 million/well (triple lateral)
10 Hz wells plus
thermal pilot
Q1-Q2/08
Apr-05
10-12 wells per section
9 Hz wells
Q3-Q4/08
5000
Primary (cold) development
-
4 Hz wells
Q1/09
Jan-05
•
11 Hz wells
Q3-Q4/09
Estimated resource potential of
prospective land = 50 million barrels of
original oil in place (OOIP) per section
bbl / d
•
B.C.
Alberta
Seal – Multi-Lateral Horizontal
2004
2005
2006
2007
2008
2009
Total
Total
Wells
Single
Two
2
4
2
17
19
17
61
2
4
2
13
1
1
23
------4
17
1
22
--------1
7
8
160
$1.1
$6,900
240
$1.3
$5,200
300
$1.5
$5,000
Average IP Rate (bbl/d)
Capex per Well ($millons)
Production Efficiency
($ per boe/d)
Number of Laterals
Three
Four

Sask.
Six
Eight
Total
Laterals
----------3
3
----------2
2
----------3
3
2
4
2
21
38
72
139
390
$1.7
$4,200
470
$1.8
$3,800
550
$2.0
$3,600
B.C.
Seal – Thermal Development
•
Modular development
- Readily executable 10-well size
- Traditional oil and gas area
- CAPEX = $31 million
Actual Cold
Alberta
Sask.

Projected Cold
Post-Steam
1000
•
300
-
EUR = 3.8 MMbbl
200
-
Projected OPEX using $6.50 per mcf
gas cost
100
First module planned by end of 2011
May-09
Apr-09
Mar-09
Feb-09
Jan-09
Dec-08
Nov-08
Oct-08
Sep-08
$14 per bbl over project life
Aug-08
-
0
Jul-08
<$10 per bbl initially
Cold Primary
Production
Jun-08
-
Inject Steam / Soak
400
May-08
Oil rate = 1,700 bbl/d (peak year) /
2,200 bbl/d (peak month)
Apr-08
-
500
Mar-08
Validated by field pilot
600
Feb-08
-
Fuel Requirement = 0.44 MCF/BS
Jan-08
Recovery factor ≈30% based on
numerical reservoir simulation
Gross SOR (without deducting cold primary) = 0.7 BS/BO
700
Dec-07
-
Incremental SOR (deducting cold primary) = 1.3 BS/BO
800
Nov-07
Recovery per 10-well module (Baytex
Estimates)
Oct-07
•
Barrels of Oil Per Day
900
B.C.
Alberta
Seal – Reserves Recognition

Sask.
Dec 31/05
Dec 31/06
Dec 31/07
Dec 31/08
Dec 31/09
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
6
8
25
44
60
Total Proved
14
62
103
106
130
Proved plus Probable
20
64
109
134
189
4
8
12
15
20
Reserves (MMbbl)
Locations Assigned Reserves
Proved Producing
Land Assigned Reserves
Sections (640 acres)
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.
B.C.
Seal – Low Environmental Impact
Baytex Seal
Non-Mining Oil Sands Development
Fort McMurray
Oil Sands Mining
Alberta

Sask.
B.C.
Alberta
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:
•
2010 E&D CAPEX: ≈ $90 million
•
2010 Drilling:
70 gross (62.3 net) wells
63 recompletions
96% success rate
≈ 70 gross (63 net) wells
≈ 70 recompletions

Sask.
B.C.
Alberta
Lloydminster Drilling Inventory
•
> 5 year drilling inventory
•
Drilling inventory has increased by
75% over the past five years
•
Development includes vertical /
horizontal / thermal (SAGD)

Heavy Oil Production (boe/d)
30,000
25,000
20,000
•
Efficiency ratios (half cycle):
- $12,100 per boe/d
- $10.10/boe based on 2P reserves
15,000
10,000
5,000
•
2010E netback of ≈ $38/boe (based
on forward strip) generates a
recycle ratio of 3.8x
0
2005
2006
2008
2007
Lloyd Heavy
Seal
2009
Sask.
Heavy Oil Investment Metrics
Before Tax ROR (%)
500
Seal Cold
Kerrobert SAGD
Lloyd Area Cold Vertical
Lloyd Area Cold Horizontal
Seal Thermal
400
300
200
100
0
30
40
50
60
70
WTI (US$)
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 $0.96
Flat prices (no escalation of oil price or gas cost)
80
90
100
Heavy Oil Pricing
Heavy Oil Differential
•
Market data suggest continued low differentials
•
Fundamental drivers suggest continued low differentials
– Reduced supply from traditional sources / Canadian oil sands growth lags forecasts
– Excess pipeline capacity now available
– Heavy oil refining has highest margins relative to other crudes
•
Forecasted demand-supply imbalance for heavy oil in North America
•
WCS differential ≈ 12.4% of WTI price (January – April 2010)
•
Majority of Baytex’s differential exposure is hedged for 2010
Heavy Oil Differential
High demand season (Apr – Sep)
Low demand season (Oct – Mar)
60
Lloyd Blend Differential
(% of WTI Price)
50
40
30
20
10
0
2005
2006
2007
2008
2009
2010
Heavy Oil Differential
60%
LLB Differential (% of WTI)
50%
40%
30%
20%
10%
0%
J
F
2001
2005
2008
M
A
M
2002
2006
2009
J
J
A
2003
2007
2010
S
O
N
D
2004
Average 2001-2007
2010 Forward Curve
Heavy Oil Differential vs. WTI
150
45
40
100
30
25
75
20
50
15
10
25
5
WTI
Lloyd Differential
Ja
n10
Ja
n09
Ja
n08
Ja
n07
Ja
n06
Ja
n05
-
Ja
n04
0
Ja
n03
WTI (US$/bbl)
35
Forward WTI
Forward Lloyd Differential
Lloyd Differential (US$/bbl)
125
Heavy Oil Differential / WTI Relationship
40
Lloyd Differential (US$/bbl)
30
20
10
0
0
25
50
75
100
125
WTI (US$/bbl)
Note: Lloyd differential shifted back one month to reflect trading sequence versus WTI cash settlement.
150
Traditional Sources of Heavy Oil
Million Barrels per Day
1.6
1.2
0.8
0.4
0.0
Maya (Mexico)
Maracaibo Basin
Heavy Blends
(Venezuela)
2008 Actual Production
Source: Wood Mackenzie, Global Oil Supply Tool, July 2009
Marlim
(Brazil)
Oriente (Ecuador) Grane (Norway)
2015 Production Forecast
Projected Canadian Oil Sands Production
4.5
2006 Forecast
Oil Sands Production
(million bbl/day)
4.0
3.5
3.0
2.5
2009 Forecast
2.0
1.5
1.0
0.5
0.0
2008
2009
May 2006
2010
2011
2012
June 2007
2013
2014
June 2008
2015
2016
2017
2018
December 2008
2019
2020
June 2009
Source: Macquarie Equities Research, January 2010 (based on Canadian Association of Petroleum Producers forecasts 2006-2009)
Infrastructure Development
Existing Major Pipelines
2006 Pipeline Reversals
Approved Pipeline (Under Construction)
Fort McMurray
Proposed Pipelines
Kitimat
Edmonton
Hardisty
Winnipeg
Superior
Calgary
Chicago
Guernsey
Patoka
Cushing
Salt Lake City
Los Angeles
Artesia
Port Arthur
Nederland
Pipeline Capacity vs. Crude Production
Thousand of Barrels Per Day
6000
Supply from Operating and
In Construction Projects
5000
Supply from Production
Growth Forecast
Keystone XL
4000
AB Clipper
Keystone
3000
Enbridge
2000
PADD IV
1000
TMPL
Express
Western Canadian Refiners
0
2009
2011
2013
2015
2017
2019
2021
2023
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.
2025
Mid-Continent Refining Margins
50
Maya Coking (USGC)
40
Bonny Lt Crking
WTI Cracking
Forcados Cracking
30
Basrah Cracking
Arab Lt. Cracking
Arab Hvy Coking
20
Lloydminster Coking
10
-
Source: Peters & Co. research, based on data from Bloomberg.
Note: Mayan coking margins are presented for the U.S. Gulf Coast.
Jan-10
Oct-09
Jul-09
Apr-09
Jan-09
Oct-08
Jul-08
Apr-08
Jan-08
Oct-07
Jul-07
Apr-07
(10)
Jan-07
Refining Margin (US$/bbl)
Brent Crking
Canadian Heavy Oil Supply-Demand Outlook
2.5
Million Barrels per Day
2
1.5
1
0.5
0
2008
2009
2010
2011
Canadian Heavy Oil Production
2012
2013
2014
2015
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

Viking

Bakken /
Three Forks

Light Oil Resource Potential
Initial Rate
(Boe/d / well)
Estimated
Recovery
(Mboe / Well)
Well Cost
($Million / well)
Bakken /
Three Forks
300
275
Viking
75
65
Total
Notes: All values shown in this table represent Baytex’s internal estimates.
C$ = US$0.95
Potential Net
Locations
Potential
CAPEX
(C$ Billion)
Potential
Recovery
(MMboe)
US$4.2
150 - 300
0.66 – 1.32
41 - 82
C$1.3
260
0.34
17
410 - 560
1.0 – 1.7
58 - 99
Light Oil Investment Metrics
100
Before Tax ROR (%)
Viking - Multi-Lateral
Viking - Multi-Stage Frac
80
Bakken-Three Forks
60
40
20
0
40
50
60
70
WTI (US$)
Assumptions:
Cdn dollar = US $0.95
No inflation of oil prices, capital costs or operating costs.
80
90
100
Hedging
Hedge Coverage
Q1 2010
Q2 2010
Q3 2010
Q4 2010
Full-Year
2010
Full-Year
2011
25%
11%
37%
34%
11%
45%
34%
11%
45%
31%
11%
43%
31%
11%
43%
0%
0%
0%
58%
12.79
16.3%
63%
13.03
14.9%
54%
13.49
15.2%
47%
13.94
15.6%
56%
13.31
15.5%
0%
21%
33%
0%
54%
21%
15%
0%
36%
22%
14%
0%
36%
24%
15%
0%
39%
22%
19%
0%
41%
6%
8%
5%
19%
$ 5.61
$ 5.74
$ 5.84
$ 5.84
$ 5.76
$ 5.21
33%
54
0.8813
35%
57
0.8899
35%
57
0.8899
35%
57
0.8899
35%
225
0.8878
16%
114
0.9274
Crude Oil
% of Crude Oil Volumes Hedged
Fixed Price (average US$77.92/bbl)
Costless Collars (average floor of US$71.67/bbl, average ceiling of US$92.97/bbl)
Heavy Oil Differentials
% of Heavy Oil Volumes Hedged
Equivalent Fixed Differential to WTI (US$/bbl)
Equivalent Percent Differential, % of WTI
-
(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)
Fixed Price
Sold Calls ( Average Strike: US$6.25/mmbtu; Avereage Premium: US$0.64)
Total Natural Gas
Average prices for fixed price contracts (C$/mcf):
Foreign Exchange
% of Foreign Exchange Hedged
Hedged Amount (US$ millions)
Average Swap Rate (USD/CAD)
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)
Swap Type
Floating Rate
Fixed Rate
Term of Contract
150
Receive-Fixed
3-month LIBOR + 787.5 bps
915 bps
Oct 2009 - Sept 2011
Interest Rate (for US$ Bank Line Draw)
Hedged Amount (US$ million)
Swap Type
Floating Rate
Fixed Rate
Term of Contract
90
90
Forward-Starting Pay-Fixed
Forward-Starting Pay-Fixed
3-month LIBOR
3-month LIBOR
4.055%
4.385%
Oct 2011 - Sep 2014
Oct 2012 - Sep 2014
Balance Sheet
Financial Strength
C$ Million
US Subordinated Notes
Dec 31
2004
Dec 31
2005
Dec 31
2006
Dec 31
2007
Dec 31
2009
Dec 31
2008
217
210
210
178
220
-
Cdn Sr Unsecured Debentures
-
-
-
-
-
150
Convertible Debentures
-
74
19
16
10
8
196
140
138
250
302
128
-
-
-
-
-
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
Bank Loan and Working Capital
(C$ draws)
Bank Loan (US$ draws)
(1)
Translated to Canadian dollars using the December 31, 2009 USD/CAD noon rate of 0.9555.
(1)
Credit Metrics
Dec 31
2004
Dec 31
2005
Dec 31
2006
Dec 31
2007
Dec 31
2008
Dec 31
2009
Credit Facility (C$ Millions)
Approved credit facility
250
250
300
370
485
515
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
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
33%
26%
18%
22%
27%
13%
Bank line undrawn
Debt / Reserves ($/boe)
Debt / Enterprise Value
Financial Projections
2010E Funds From Operations (C$ Millions)
Heavy Oil Differential (% of WTI)
10%
WTI
(US$/bbl)
Strip
15%
20%
$70
$398
$375
$351
$80
$473
$446
$419
$518
$488
Strip
$90
$483
$548
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 = $203 million.
2010E Debt to Funds From Operations
Heavy Oil Differential (% of WTI)
10%
WTI
(US$/bbl)
Strip
15%
20%
$70
1.3x
1.4x
1.6x
$80
0.9x
1.1x
1.2x
0.8x
0.9x
0.9x
Strip
$90
0.7x
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.
2010E Surplus Cash Flow
Heavy Oil Differential (% of WTI)
10%
15%
20%
Surplus Cash Flow (C$ Millions)
Funds From Operations
E & D CAPEX
Free Cash Flow
Distributions (net of DRIP)
Surplus Cash Flow
520
(235)
285
(203)
82
479
(235)
244
(203)
41
450
(235)
215
(203)
12
Funds From Operations per Unit
Cash Distributions per Unit
4.69
2.16
4.31
2.16
4.05
2.16
Payout Ratio (net of DRIP)
Basic
Total
40%
84%
42%
91%
45%
97%
YE 2010 Total Debt (C$ Millions)
Debt to Funds From Operations Ratio
404
0.8x
432
0.9x
460
1.0x
Notes:
(1)
(2)
(3)
(4)
(5)
(6)
Assumes average 2010 production of 43,500 boe/d.
Table based on April 6, 2010 strip. Strip prices are WTI = US$86.03/bbl, NYMEX price =US$4.62/mmbtu, average FX = US$0.997/Cdn$.
Payout Ratios are calculated net of distribution reinvestment program (“DRIP”). DRIP proceeds typically ≈ 15% of distributions.
Basic Payout Ratio = Cash distributions / Funds From Operations.
Total Payout Ratio = Cash distributions + capital expenditures / Funds From Operations.
Debt to Funds From Operations Ratio is based off forecast year-end 2010 total debt and 2010E Funds From Operations.
2010E Funds From Operations Sensitivities
Funds From Operations Impact
(C$ Millions)
With Current
Without
Hedges
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
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 .
Relative Performance / Valuation
Total Return Performance
Baytex Energy Trust
S&P/TSX Composite Index
S&P/TSX Capped Energy Trust Index
S&P 500
800
700
600
500
400
300
200
100
0
Jan-10
Sep-09
May-09
Jan-09
Sep-08
May-08
Jan-08
Sep-07
May-07
Jan-07
Sep-06
May-06
Jan-06
Sep-05
May-05
Jan-05
Sep-04
May-04
Jan-04
Sep-03
Note: Total return includes capital appreciation, cash distributions and reinvestment of distributions to April 6, 2010
Source: TSX Historical Data, Bloomberg Data, and Company information
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%.
Contact Information
Anthony W. Marino
President and CEO
(403) 267-0708
Baytex
Baytex
Brian Ector
Director of Investor Relations
(403) 267-0702
Baytex
W. Derek Aylesworth
Chief Financial Officer
(403) 538-3639
Cheryl Arsenault
Investor Relations
(403) 267-0761
Baytex Energy Trust
Suite 2200, Bow Valley Square II
205 – 5th Avenue S.W.
Calgary, Alberta T2P 2V7
Telephone: (403) 269-4282
1-800-524-5521
Website: www.baytex.ab.ca