AR Cover 04 3/22/05 10:10 AM Page 1
2004
901, 1015 – 4TH ST SW
CALGARY, ALBERTA T2R 1J4
Annual Report
AR Cover 04 3/22/05 10:10 AM Page 3
Trust Profile
Bonterra Energy Income Trust. (TSX symbol – BNE.UN) is an energy income trust that develops and
produces oil and natural gas in the Provinces of Alberta and Saskatchewan.
The Trust’s business strategy is to strive to maximize Unitholder’s value by applying long-term growth
objectives. The Trust’s primary objective is to combine its oil and gas production technical strengths with
planned business strategies to generate above average results and returns for its Unitholders.
Contents
Highlights
Report to Unitholders
Review of Operations
Property Discussions
Management’s Discussion and Analysis
Management’s Responsibility for Financial Statements
Auditors’ Report
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Trust Information
Notice of Annual General Meeting
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IBC
The Annual General Meeting of Unitholders will be held on Monday, May 16, 2005, in the Nikiska Room,
Main Lobby Level, at the Westin Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m.
Forward-Looking Information
Certain information set forth in this document, including management’s assessment of Bonterra Energy Income Trust’s (“the Trust” or
“Bonterra”) future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject
to numerous risks and uncertainties, some of which are beyond Bonterra’s control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market
volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used
in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as
such, undue reliance should not be placed on forward-looking statements. Bonterra’s actual results, performance or achievement could
differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits
Bonterra will derive therefrom. Bonterra disclaims any intention or obligation to update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not
represent fair market value of reserves.
Trust Information
Board of Directors
G.J. Drummond, Nassau, Bahamas
G.F. Fink, Calgary, Alberta
C.R. Jonsson, Vancouver, British Columbia
F. W. Woodward, Calgary, Alberta
Officers
G.F. Fink – President & Chief Executive Officer
R.M. Jarock – Chief Operating Officer
G.E. Schultz – Vice President, Finance,
Chief Financial Officer, & Secretary
Registrar & Transfer Agent
Olympia Trust Company, Calgary, Alberta
Auditors
Deloitte & Touche LLP, Calgary, Alberta
Solicitors
Parlee McLaws, Calgary, Alberta
Tupper, Jonsson & Yeadon,
Vancouver, British Columbia
Bankers
The Royal Bank of Canada, Calgary, Alberta
Stock Listing
The Toronto Stock Exchange, Toronto, Ontario
Trading symbol: BNE.UN
Web Site
www.bonterraenergy.com
Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488
Bonterra Text 3/22/05 10:36 AM Page 1
Highlights
Financial ($000, except $ per share)
Revenue – oil and gas (net of royalties)
Distribution per Unit
Funds Flow from Operations (1)
Per Unit Basic
Per Unit Fully Diluted
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Capital Expenditures and Acquisitions
Outstanding Debt
Unitholders’ Equity
Units Outstanding (000’s)
Operations
Oil and Liquids (barrels per day)
Average Price ($ per barrel)
Natural Gas (MCF per day)
Average Price ($ per MCF)
Total barrels per day (BOE per day) (2)
Reserves
Oil and Liquids (barrels in 000’s)
Proven Developed Producing (Gross) (3)
Proven plus Probable (Gross) (3)
Natural Gas (MCF in 000’s)
Proven Developed Producing (Gross) (3)
Proven plus Probable (Gross) (3)
Reserve Life Index (Oil, liquids and natural gas @6:1)
Proven Developed Producing (4)
Proven plus Probable (4)
Reserves in BOE’s per Weighted Average Outstanding Unit
Proven Developed Producing
Proven plus Probable
Trust Units Trading Statistics
Unit Prices (based on daily closing price)
High
Low
Close
Daily Average Trading Volume
$
$
$
2004
2003(5)
$
$
$
47,966
1.88
29,606
2.08
2.03
20,366
1.43
1.40
10,943
3,861
54,060
14,943
2,361
47.30
4,996
6.81
3,194
11,956
16,084
17,021
21,762
12.4
16.5
1.04
1.39
26.00
15.15
25.10
22,918
38,381
1.55
22,228
1.66
1.64
14,016
1.05
1.04
5,691
21,830
36,983
13,521
2,384
39.65
4,403
5.45
3,118
11,032
13,357
15,978
19,031
11.8
14.3
1.01
1.22
15.85
9.10
15.50
14,576
(1) Funds flow from operations is not a recognized measure under GAAP. Management believes that in addition to net earnings, funds flow from operations
is a useful supplemental measure as it demonstrates the Trust’s ability to generate the cash necessary to make trust distributions, repay debt or fund future
growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Trust’s performance.
The Trust’s method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For
these purposes, the Trust defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items.
(2) BOE’s are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the wellhead and as such may be misleading if used in isolation.
(3) Gross reserves relate to the Trusts ownership of reserves before royalty interests.
(4) The reserve life index is calculated by dividing the reserves (in BOE’s) by the annualized fourth quarter average production rate in BOE/d (2004 - 3,268,
2003 – 3,172).
(5) Figures have been restated to conform to current accounting policies. See notes to financial statements.
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Bonterra Text 3/22/05 10:36 AM Page 2
Report to Unitholders
Bonterra Energy Income Trust (“Bonterra”) is pleased to report its operational and financial results for
the year and to provide information about its acquisition of Novitas Energy Ltd. (Novitas) on January 7,
2005. The Trust had a successful growth year and its annual distributions and capital appreciation
resulted in a rate of return to Unitholders of 74 (2003 – 78) percent, far exceeding the return of most
trusts and corporations.
Operations
Bonterra’s production is ideally suited for a trust.
Approximately 75 percent of its production is
mainly light, sweet gravity crude and liquids, and
the remaining 25 percent natural gas is sweet long-
life production. The life index for the Trust’s proven
developed producing reserves is 12.4 years, which is
significantly higher
trusts.
Bonterra’s life index including all categories of
proven and probable reserves is 16.5 years. The
reserves have been calculated by Sproule Associates
Limited, independent engineers. Reserves in BOE’s
per weighted average outstanding units increased by
14 percent, from 1.22 in 2003 to 1.39 in 2004.
than most other
The long life index allows the Trust to distribute a
higher percentage of its cash flow to Unitholders
rather than using it for capital expenditures to
maintain production volumes. Bonterra’s annual
actual decline rate from existing properties is
approximately
seven percent before capital
expenditures.
Production volumes for 2004 averaged 3,194 barrels
of oil equivalent (BOE’s) per day compared to 3,118
BOE’s per day in 2003. The December 31, 2004, exit
production was approximately 3,330 BOE’s per day.
Six Pembina Cardium oil wells and five Pembina
shallow gas wells were drilled in Q4, 2004, most of
which should be on production by the end of Q2
2005. Bonterra has high working interests in these
wells.
Acquisition of Novitas in January 2005
In January 2005 Bonterra was successful in
acquiring 100 percent of all of the issued and
outstanding shares of Novitas for $769,000 in cash
and 1,335,745 units of Bonterra. Since the
acquisition did not become effective until January
2005, this report does not include Novitas. At the
closing in January 2005, Novitas production was
approximately 600 BOE’s.
Financial
Bonterra’s distribution for 2004 was $1.88 compared
to $1.55 for 2003. The taxable portion in 2004 was
58.51 (2003 – 68.92) percent and 41.49 (2003 –
31.08) percent is a return of capital.
Revenue (net of royalties) from commodity sales was
$47,966,000 in 2004 compared to $38,381,000 for
the preceding year. Commodity prices were $47.30
(2003 - $39.65) per barrel of oil and natural gas
liquids, and $6.81 (2003 - $5.45) per MCF for natural
gas.
At year-end Bonterra’s debt was approximately
$3,861,000 (2003 - $21,830,000), less than two
months funds flow on an annualized basis. This level
of debt falls within the Trusts objective of debt being
less than one year’s cash flow.
Outlook
The objectives for the Trust are to increase its
production volumes and reserves in the future by
developing its existing properties and by acquiring
additional production. During 2005 Bonterra
estimates that it will participate in drilling
approximately 50 wells. The majority of these wells
will be drilled on Trust operated and high working
interest locations, mainly in the Cardium and
shallow gas zones in the Pembina field. The Trust
also continues to look for strategic acquisitions that
compliment its portfolio and will provide a benefit
to Unitholders over the long term.
The Trust is optimistic with regard to its drill
programs and its ability to continue to provide high
returns and additional appreciation of its unit price.
It should be noted that since Bonterra Energy Corp.
(predecessor to the Trust) was incorporated and
listed publicly in mid 1998, for every $100 invested
at that time, a Unitholder that held continuously
from that date to December 31, 2004, would have
received $1,279 in distributions and have Trust Units
worth $5,553.
The Board of Directors of the operating company
and management wish to thank the Unitholders for
their continued loyal support and advice and the
staff for the significant contributions made by them.
Submitted on behalf of the Board of Directors,
George F. Fink
President, CEO and Director
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Bonterra Text 3/22/05 10:36 AM Page 3
Review of Operations
Reserves
The Trust engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective
date of December 31, 2004. The reserves are located in the Provinces of Alberta and Saskatchewan. The
majority of the Trust’s production is comprised of light sweet crude, which results in higher oil prices, and
better marketing opportunities. The Trust’s main producing areas are located in the Pembina area of Alberta
and Dodsland area of Saskatchewan. The gross reserve figure in the following charts represents the Trust’s
ownership interest before royalties and the net figure is after deductions for royalties.
Summary of Oil and Gas Reserves as of December 31, 2004
(Forecast Prices and Costs)
Light and
Medium Oil
Net
(Mbbl)
Gross
(Mbbl)
Reserves
Natural
Gas
Natural Gas
Liquids
Gross
(MMcf)
Net
(MMcf)
Gross
(Mbbl)
Net
(Mbbl)
Reserve Category
Proved
Developed Producing
10,758
10,301
17,021
12,797
1,198
Developed Non-Producing
Undeveloped
Total Proved
Probable
150
633
11,541
2,936
137
582
422
845
11,020
18,288
2,797
3,473
Total Proved Plus Probable
14,477
13,817
21,761
365
567
13,729
2,480
16,209
Reconciliation of Trust Gross Reserves by Principal Product Type
(Forecast Prices and Costs)
860
8
57
925
226
12
82
1,292
316
1,608
1,151
Gross Proved
(Mbbl)
Light and
Medium Oil
Gross Probable Gross Proved
Plus Probable
(Mbbl)
(Mbbl)
Natural
Gas
Gross Proved
(MMcf)
Gross Probable Gross Proved
Plus Probable
(MMcf)
(MMcf)
December 31, 2003
10,618
1,864
12,482
16,634
2,397
19,031
Improved recovery
Technical revisions
Production
353
1,374
(804)
116
956
-
469
2,330
613
2,869
277
799
890
3,668
(804)
(1,828)
-
(1,828)
December 31, 2004
11,541
2,936
14,477
18,288
3,473
21,761
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Bonterra Text 3/27/05 3:17 PM Page 4
Summary of Net Present Values of Future Net Revenue as of December 31, 2004
(Forecast Prices and Costs)
Net Present Value of Future Net Revenue
(M$)
Reserve Category
Proved
0
Before and After Income Taxes Discounted at (%/year)
20
15
10
5
Developed Producing
241,109
169,990
133,774
112,115
97,685
Developed Non-Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
4,785
11,759
257,653
79,957
337,610
4,106
8,305
182,401
35,042
217,443
3,586
6,104
143,464
19,901
3,178
4,572
2,851
3,433
119,865
103,969
13,397
9,647
163,365
133,072
113,616
Commodity prices used in the above calculations of reserves are as follows:
Year
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
Edmonton
Par Price
(Cdn $ per barrel)
Alberta Gas Reference
Price Plantgate
(Cdn $ per MCF)
Propane
Butane
Pentane
(Cdn $ per barrel)
(Cdn $ per barrel)
(Cdn $ per barrel)
51.25
48.03
42.64
38.31
36.36
36.91
37.47
38.03
38.61
39.19
39.78
6.76
6.45
6.00
5.55
5.21
5.31
5.38
5.48
5.58
5.68
5.79
32.09
30.07
26.70
23.98
22.76
23.11
23.46
23.81
24.17
24.53
24.90
38.20
34.01
30.20
27.13
25.75
26.13
26.53
26.93
27.34
27.75
28.17
52.49
49.19
43.67
39.23
37.24
37.80
38.37
38.95
39.54
40.14
40.74
Crude oil, natural gas and liquid prices escalate at 1.5% per year thereafter.
The following cautionary statements are specifically required by NI 51-101
• It should not be assumed that the estimates of future net revenue presented in the above tables represent
the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions
will be attained and variances could be material.
• Disclosure provided herein in respect of BOE’s may be misleading, particularly if used in isolation. In
accordance with NI 51-101, a BOE conversion ratio of 6mcf:1bbl has been used in all cases in this disclosure.
This BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the wellhead.
• Estimates of reserves and future net revenues for individual properties may not reflect the same confidence
level as estimates of reserves and future net revenues for all properties due to the effects of aggregation.
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Bonterra Text 3/22/05 10:36 AM Page 5
Production
The following table provides a summary of production volumes from the Trust’s main producing areas:
2004
2003
Oil and NGL
(Bbls/day)
Natural Gas
(MCF/day)
Oil and NGL
(Bbls/day)
Natural Gas
(MCF/day)
1,729
388
59
42
42
101
2,361
4,231
207
50
53
18
437
4,996
1,733
399
50
46
42
114
2,384
3,502
268
53
72
15
493
4,403
Pembina, Alberta
Dodsland, Saskatchewan
Pinto, Saskatchewan
Redwater, Alberta
Midale, Saskatchewan
Other
Land Holdings
The Trust’s holdings of petroleum and natural gas leases and rights are as follows:
Alberta
Saskatchewan
2004
2003
Gross Acres
Net Acres
Gross Acres
Net Acres
113,697
32,584
146,281
67,159
19,524
86,683
113,057
32,584
145,641
66,519
19,524
86,043
Petroleum and Natural Gas Capital Expenditures
The following table summarizes petroleum and natural gas capital expenditures incurred by the Trust on acquisitions,
land, seismic, exploration and development drilling and production facilities for the years ended December 31:
Acquisitions
Exploration and development costs
Pipeline projects
Seismic
Land costs
2004
$
-
10,055,000
302,000
-
236,000
2003
$
32,000
5,226,000
30,000
3,000
96,000
Net petroleum and natural gas capital expenditures
$10,593,000
$5,387,000
Drilling History
The following table summarizes the Trust’s gross and net drilling activity and success:
2004
Crude Oil
Natural Gas
Dry
Total
Success rate
Development
Exploratory
Total
Gross
19
21
2
42
Net
5.8
18.6
1.8
26.2
Gross
Net
Gross
-
1
-
1
-
1
-
1
19
22
2
43
Net
5.8
19.6
1.8
27.2
95.2%
93.1%
100%
100%
95.3%
93.3%
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Bonterra Text 3/27/05 3:18 PM Page 6
Crude Oil
Natural Gas
Dry
Total
Success rate
Crude Oil
Natural Gas
Dry
Total
Success rate
2003
Development
Exploratory
Gross
31
3
-
34
Net
3.27
3.00
-
6.27
Gross
-
6
-
6
Net
-
5.8
-
5.8
Total
Gross
31
9
-
40
Net
3.3
8.8
-
12.1
100%
100%
100%
100%
100%
100%
2002
Development
Exploratory
Gross
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1
-
2
Net
.1
1.0
-
1.1
Gross
-
9
-
9
Net
-
7.3
-
7.3
Total
Gross
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-
11
Net
0.1
8.3
-
8.4
100%
100%
100.%
100%
100%
100%
Market Performance
The following graph illustrates changes over the past six and a half years in the value of $100 invested in
Bonterra (of Common Shares of Bonterra Energy Corp. prior to July 1, 2001) or Trust Units, as the case may
be, the TSX Composite Index and the TSX Energy Index
CUMULATIVE TOTAL RETURN ON $100 INVESTMENT
7000
6000
5000
4000
3000
2000
1000
0
DEC 1998
DEC 1999
DEC 2000 DEC 2001 DEC 2002 DEC 2003
DEC 2004
Bonterra Energy Income Trust (1)
$245
$550
$900
$1,512
$2,644
$4,292
$6,832
Dec 1998
Dec 1999
Dec 2000
Dec 2001
Dec 2002
Dec 2003
Dec 2004
TSX Composite Index
TSX Energy Index
$ 92
$119
$127
$ 109
$ 94
$ 117
$ 132
$ 83
$ 99
$144
$ 148
$ 166
$ 205
$ 264
Note (1)
Includes distributions of $5.66 per unit since becoming a Trust.
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Bonterra Text 3/22/05 10:36 AM Page 7
Property Discussions
Bonterra has an excellent asset base consisting of long life, low risk and predictable reserves with upside, and
management that has proven it can manage these high quality assets to generate long-term value. Our
producing properties are located in the Pembina area of Alberta, the East Central area of Alberta, the Dodsland
area in southwest Saskatchewan, and the southeast area of Saskatchewan. Subsequent to year end Bonterra
has added quality properties in the Shaunavon area of southwest Saskatchewan and the Peck Lake area of
west central Saskatchewan. Bonterra continues to acquire exploration lands in the Pembina area of Alberta,
is pursuing other drilling opportunities in Alberta and Saskatchewan, and reviews and assesses producing and
non-producing properties for acquisitions on an ongoing basis in various areas in Western Canada.
Pembina Area, West Central Alberta
operators in the Pembina area are reducing well
The Pembina field is the largest conventional oil
field in Canada and contains our most significant
producing property. Our production is predominately
predictable, long life, low decline and high quality
light oil from the Cardium formation that is located
at a depth of approximately 1,550 meters. Bonterra
operates approximately 85 percent of its production
in this large core area which allows for significant
spacing to 40 acres Bonterra is reducing its spacing
to 160 or 80 acres in most areas. The initial 2004
drilling results have been very positive and have
provided the Trust with enough information to
continue with and expand this program. Bonterra
has a significant number of Cardium infill locations
that can be drilled to replace existing production
and grow its reserves.
operating efficiencies. The property contains
Bonterra is also producing from the Belly River
approximately 345 gross
(276 net) operated
formation. The Belly River produces high quality
producing wells with an 80 percent average working
light sweet oil from a depth of approximately 1,100
interest and 137 gross (23.7 net) non-operated
meters. There is potential to increase production
producing wells with an approximate 17 percent
from the Belly River formations through drilling in
average working interest.
select areas of the field.
The Trust’s large land holdings and strong
Bonterra has been able to increase natural gas
infrastructure position provides a strong base to
production and reserves by drilling multi-zone
exploit a range of low risk development and
shallow gas wells into the Edmonton and Paskapoo
exploration opportunities. Even though the Pembina
formations. The Trust is targeting several productive
area is considered a mature field it is proving to be
sands that range in depth from 275 to 750 meters.
a significant area for multi-zone oil and natural gas
Bonterra will continue to build on its previous
exploration. The Trust has managed to increase
exploration success in the area and develop these
produced reserves in the area through optimization
low cost shallow natural gas reserves.
and drilling as well as through key acquisitions.
Bonterra has been assessing production of coal-bed
An ongoing Cardium infill drilling program was
methane (CBM) in this area for a period of three
initiated on our non-operated properties in 2003. In
years with encouraging initial results. Based on the
late 2004 the Trust started an infill drilling program
initial results Bonterra had hoped to proceed with a
on its operated Cardium properties. Where most
program of re-entering existing wells and drilling
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Bonterra Text 3/22/05 10:36 AM Page 8
new wells to further assess the CBM potential. Due
producing property which consists of 56 producing
to regulatory delays and uncertainty, Bonterra has
wells
in the Shaunavon area of southwest
delayed this project until all regulatory concerns are
Saskatchewan where the Company’s working
rectified. It is anticipated that these concerns will be
interest averages approximately 94 percent. The
resolved in Q2, 2005. Bonterra has extensive
properties are located in the Whitemud and
prospective land holdings near existing operated
Chambery fields and produce 22 degree API crude
infrastructure in the area. CBM has the potential to
oil from the upper Shaunavon formation located at
add significant low risk production and reserves and
a depth of approximately 1,500 meters. A portion of
the Trust will continue to pursue this opportunity.
the property is being produced under waterflood
Dodsland Area, Southwest Saskatchewan
The Dodsland properties produce light sweet gravity
oil and solution gas from the Viking formation at a
depth of approximately 700 meters. Bonterra now
operates approximately 425 gross (374 net) wells
with an average working interest of 88 percent.
This is low rate stable production so cost control and
hedge programs are important focuses of our
operating strategy in this area. The Trust is
continually reviewing different operating practices
with the majority of the properties still on primary
production. The primary production areas are being
monitored on an ongoing basis to determine if water
flood programs should be initiated. The wells in the
Shaunavon area generally have a very long life and
stable low decline production profile after a short
period of higher decline when a new well initially
commences production.
The Trust is reviewing geological information
obtained from development on and near our existing
lands and is using it to locate potential exploration
and improved technology that may improve the
or development prospects in the area.
profitability of the property. Bonterra does not have
an abandonment or reclamation liability for this
Peck Lake Area, West Central Saskatchewan
property because under terms of an agreement
This property was also obtained in the Novitas
Bonterra has an option to transfer uneconomic wells
acquisition in January 2005. The Peck Lake property
to the previous owner of the property.
is a 100 percent owned and operated shallow gas
Southeast Saskatchewan
The southeast properties produce slightly sour high
gravity oil and solution gas from the Midale
formation. The Trust has an average working
property located in west central Saskatchewan with
four producing gas wells. The property was brought
on production in late November, 2004, and is
performing to expectations. The Trust will be
looking to expand in this area to maximize the value
interest of approximately 98 percent of its properties
of its operated infrastructure.
in the area. Bonterra continues to evaluate this area
to determine if further optimization programs may
Other
increase overall profitability of the properties.
Bonterra has varying interests in other producing
Shaunavon Area, Southwest Saskatchewan
This property was acquired in January 2005 (the
Novitas acquisition). Bonterra operates this major
and non-producing properties in various other areas
of Alberta and Saskatchewan. Most of these
properties are long term producers and may provide
opportunities for increased interests in the future.
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Management’s Discussion and Analysis
This report dated March 9, 2005 is a review of the operations, current financial position and outlook
for the Trust and should be read in conjunction with the audited financial statements for the year ended
December 31, 2004, together with the notes related thereto.
Annual Comparisons
Financial ($000, except $ per unit)
Revenue - oil and gas (net of royalties)
Funds Flow from Operations (1)
Per Unit Basic
Per Unit Fully Diluted
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Cash Distributions per Unit
Capital Expenditures and Acquisitions
Total Assets
Outstanding Loans
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
Quarterly Comparisons
2004
$47,966
29,606
2.08
2.03
20,366
1.43
1.40
1.88
10,943
84,989
3,861
54,060
2,361
4,996
2003 (2)
2002 (2)
$36,424
19,458
1.50
1.50
12,474
0.96
0.96
1.43
52,751
76,417
18,357
41,892
2,464
4,287
$38,381
22,228
1.66
1.64
14,016
1.05
1.04
1.55
5,691
77,837
21,830
36,983
2,384
4,403
2004
Financial ($000, except $ per unit)
4th
3rd
2nd
1st
$13,166
$12,790
$11,223
$10,787
Revenue - oil and gas (net of royalties)
Funds Flow from Operations (1)
Per Unit Basic
Per Unit Fully Diluted
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Cash Distributions
Capital Expenditures and Acquisitions
Total Assets
Outstanding Loans
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
8,678
0.57
0.56
6,389
0.42
0.41
0.55
6,038
84,989
3,861
54,060
2,355
5,478
7,499
0.52
0.50
5,393
0.38
0.37
0.51
1,476
80,811
4,995
56,380
2,339
5,214
6,936
0.51
0.50
4,336
0.32
0.31
0.43
832
79,804
2,781
57,987
2,349
4,643
Oil and NGL Production (Bbls/day)
Natural Gas Production (Mcf/day)
2002
2003
2004
2,464
2002
2,384
2003
2,361
2004
6,493
0.48
0.47
4,248
0.31
0.31
0.39
2,597
80,540
22,070
38,615
2,401
4,641
4,287
4,403
4,996
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Quarterly Comparisons
Financial ($000, except $ per unit)
Revenue - oil and gas (net of royalties)
Funds Flow from Operations (1)
Per Unit Basic
Per Unit Fully Diluted
Net Earnings
Per Unit Basic
Per Unit Fully Diluted
Cash Distributions
Capital Expenditures and Acquisitions
Total Assets
Outstanding Loans
Unitholders’ Equity
Operations
Oil and Liquids (barrels per day)
Natural Gas (MCF per day)
4th
$ 9,529
5,814
0.44
0.43
3,502
0.26
0.25
0.36
2,665
77,837
21,830
36,983
2,429
4,272
2003(2)
2nd
$ 9,310
4,907
0.37
0.37
3,043
0.23
0.23
0.40
1,055
77,780
20,960
40,276
2,382
4,297
3rd
$ 9,587
5,319
0.39
0.38
3,223
0.24
0.24
0.38
1,453
77,429
21,642
38,355
2,325
4,386
1st
$ 9,955
6,188
0.46
0.46
4,248
0.32
0.32
0.41
518
77,136
18,792
42,722
2,400
4,661
(1) Funds flow from operations is not a recognized measure under GAAP. Management believes that in addition to net earnings, funds flow from operations is a
useful supplemental measure as it demonstrates the Trust’s ability to generate the cash necessary to make trust distributions, repay debt or fund future growth
through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Trust’s performance. The Trust’s
method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For these purposes,
the Trust defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items.
(2) Figures have been restated to conform to current accounting policies. See notes to financial statements.
Acquisition of Novitas Energy Ltd.
Effective January 7, 2005, the Trust acquired all of the issued and outstanding shares in Novitas Energy Ltd.
(Novitas). The Trust issued 1,335,745 units and paid $769,000 in cash for Novitas. For accounting purposes,
Novitas was considered a related party due to having the same directors and officers as the Trust. Given this
related party status the acquisition of Novitas will be recorded at the net book value of Novitas immediately
prior to the acquisition.
The acquisition of Novitas will add approximately 2,200,000 BOE’s of proved plus probable reserves including
approximately 1,800,000 proved reserves. Anticipated production from Novitas for 2005 is approximately
600 BOE’s per day.
The reserve data set forth below for Novitas is based on an evaluation by Sproule Associates Ltd. (Sproule)
dated October 15, 2004 with an effective date of September 30, 2004. The reserves data summarizes the oil,
liquids and natural gas reserves of Novitas and the net present value of future net revenue for those reserves
using forecast prices and costs. The reserves data conforms with the requirements of National Instrument
51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). The Trust engaged Sproule to provide
an evaluation of proved plus probable reserves and no attempt was made to evaluate possible reserves. There
is no assurance that forecast prices and cost assumptions will be attained and variances could be material.
The reserves data should be read in conjunction with the Reserves Information on page 4 which sets out the
cautionary statements that are specifically required by NI 51-101.
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Summary of Oil and Gas Reserves as of September 30, 2004
Novitas Energy Ltd.
(Forecast Prices and Costs)
Light and
Medium Oil
Net
(Mbbl)
Gross
(Mbbl)
Reserves
Natural
Gas
Natural Gas
Liquids
Gross
(MMcf)
Net
(MMcf)
Gross
(Mbbl)
Net
(Mbbl)
Reserve Category
Proved
Developed Producing
1,530
1,338
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
-
1,530
309
1,839
-
1,338
278
1,616
68
1,670
1,738
982
2,720
67
1,296
1,363
798
2,161
2
-
2
3
5
1
-
1
2
3
Summary of Net Present Values of Future Net Revenue as of September 30, 2004
Novitas Energy Ltd.
(Forecast Prices and Costs)
(M$)
Reserve Category
Proved
Developed Producing
Undeveloped
Total Proved
Probable
Total Proved Plus Probable
Net Present Value of Future Net Revenue
Before and After Income Taxes Discounted at (%/year)
0
5
10
15
20
12,528
3,486
16,014
4,297
20,311
10,160
2,938
13,098
2,840
15,938
8,648
2,531
11,179
2,145
13,324
7,611
2,219
9,830
1,748
6,856
1,972
8,828
1,484
11,578
10,312
Commodity prices used in the above calculations of reserves are as follows:
Year
Hardisty Lloyd- Alberta Gas Reference
Blend 22.3 API
(Cdn $ per barrel)
Price Plantgate
(Cdn $ per MCF)
Propane
Butane
Pentane
(Cdn $ per barrel)
(Cdn $ per barrel)
(Cdn $ per barrel)
2004 -3 mo
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
39.25
37.39
35.16
32.69
30.75
28.55
29.08
29.62
30.17
30.72
31.28
31.86
6.11
6.79
6.23
5.90
5.63
5.35
5.45
5.53
5.63
5.73
5.84
5.95
34.27
31.86
28.90
26.72
24.57
23.21
23.56
23.92
24.28
24.65
25.02
25.40
40.81
37.93
32.69
30.23
27.79
26.26
26.65
27.06
27.46
27.88
28.30
28.73
56.07
52.12
47.28
43.72
40.20
37.98
38.55
39.13
39.72
40.32
40.93
41.55
Crude oil, natural gas and liquid prices escalate at 1.5% per year thereafter.
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Production
The Trust’s 2004 average production of oil and natural gas liquids was 2,361 (2003 – 2,384) barrels per day
and natural gas production in 2004 averaged 4,996 (2003 – 4,403) MCF per day. Oil production declined by
approximately one percent while gas production increased by approximately 13.5 percent. The Trust’s fourth
quarter production saw increases in both crude oil and natural gas production due to commencement of
production from new wells drilled in the spring and summer of 2004.
The Trust’s overall annual decline rate is approximately seven percent which the Trust was able to more than
offset with its 2004 spring and summer drill programs. The Trust drilled six gross (4.9 net) oil wells and five
gross (4.4 net) natural gas wells in late November and December of 2004. None of these wells were on
production by the end of 2004. Currently the Trust has three gross (2.4 net) of the oil wells on production. It
is anticipated that two (1.8 net) more of the oil wells will be on production by the end of March with the final
well requiring further development work prior to production. The natural gas wells are in the process of being
completed and tied in with anticipated production from these wells commencing in the second quarter of
2005. Also, as discussed above, the Trust will have approximately 600 additional BOE’s per day commencing
in January from the Novitas acquisition.
Crude oil development drilling has been completed on two of the Trust’s non-operated interests with net
production gains in the fourth quarter of approximately 35 barrels per day. Additional drilling is anticipated
to be completed on the Trusts non-operated interests in the first quarter of 2005.
Revenue
Gross revenue from petroleum and natural gas sales prior to royalties was $53,585,000 (2003 - $43,449,000).
The increase of $10,136,000 was substantially due to increases in the average price received for crude oil and
natural gas liquids from $39.65 per barrel in 2003 to $47.30 per barrel in 2004 and from $5.45 per MCF in
2003 to $6.81 per MCF in 2004 for natural gas. During the fourth quarter prices received for crude oil
exceeded $50 per barrel.
Over 95 percent of the Trust’s crude oil production consists of light sweet crude with nominal quality and
transportation adjustments. Natural gas production consists primarily of dry sweet natural gas.
Although the Trust received much higher net commodity prices in 2004 than in 2003, substantial increases
in the price of U.S. WTI oil prices and U.S. Nymex natural gas prices were partially offset by the rising
Canadian dollar. The negative impact of the rising Canadian dollar on the 2004 funds flow from operations
compared to the 2003 funds flow from operations was approximately 28 cents per unit and approximately
26 cents per unit on net earnings.
Gross revenue has been reduced by $2,526,000 (2003 - $3,150,000) due to lower prices received as a result
of price hedging. The Trust will continue to assess hedging of future production (see Business Prospects, Risks,
and Outlooks) to assist in managing its cash flow. The Trust continues to follow the policy of protecting high
cost production with hedges that provide a significant level of profitability and also to provide for a
reasonable amount of cash flow protection for development projects. The Trust will however maintain a
policy of not hedging more than 50 percent of production to allow it to benefit from any price movements
in either crude oil or natural gas.
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Commodity price hedges outstanding as of the date of this report are as follows:
Period of Agreement
Commodity
Volume per Day
Index
Price (Cdn.)
January 1, 2005 to March 31, 2005
April 1, 2005 to June 30, 2005
April 1, 2005 to July 31, 2005
July 1, 2005 to September 30, 2005
Crude Oil
Crude Oil
Crude Oil
Crude Oil
October 1, 2005 to December 31, 2005
Crude Oil
January 1, 2006 to March 31, 2006
Crude Oil
500 barrels
500 barrels
500 barrels
500 barrels
500 barrels
500 barrels
WTI
WTI
WTI
WTI
WTI
WTI
$43.08 per barrel
$48.52 per barrel
$66.56 per barrel
$50.02 per barrel
$55.60 per barrel
$55.12 per barrel
January 1, 2005 to March 31, 2005
Natural Gas
1,500 GJ’s
AECO
$6 per GJ floor
January 1, 2005 to March 31, 2005
Natural Gas
1,500 GJ’s
AECO
$5.70 per GJ floor
April 1, 2005 to October 31, 2005
Natural Gas
2,000 GJ’s
AECO
$5.50 per GJ floor
November 1, 2005 to March 31, 2006
Natural Gas
1,500 GJ’s
AECO
$6.00 per GJ floor
and $9.45 per GJ ceiling
and $7.75 per GJ ceiling
and $9.00 per GJ ceiling
and $9.50 per GJ ceiling
Royalties
Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and
Saskatchewan. During 2004 the Trust paid $4,379,000 (2003 - $3,967,000) Crown royalties and $1,240,000
(2003 - $1,098,000) freehold royalties, gross overriding royalties and net carried interests. The majority of the
Trust’s wells are low productivity wells and therefore have low Crown royalty rates. The Trust’s average
Crown royalty rate is approximately eight percent (2003 – eight percent) and approximately two percent
(2002 – two percent) for other royalties before hedging adjustments. The acquisition of Novitas will result in
a slight increase in 2005 in the royalty rate as Novitas’ royalty rate is approximately 18 percent of revenue.
The Trust is eligible for Alberta Crown royalty rebates for Alberta production from all wells that it drilled on
Crown lands and from a small amount from purchased wells.
Production Costs
Production costs totalled $16,438,000 in 2004 compared to $14,110,000 in 2003. On a barrel of oil equivalent
(BOE) basis, 2004 operating costs were $14.06 compared to $12.39 for 2003. BOE’s are calculated using a
conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and
as such may be misleading if used in isolation.
Increased maintenance costs of approximately $750,000 associated with the Trust’s Dodsland operations
resulted in an increase in BOE costs in this area to $25.42 per BOE in 2004 compared to $19.54 per BOE in
2003. Also, additional maintenance costs of approximately $375,000 were incurred on the Trust’s Pinto
operations. The maintenance programs resulted in a reduction in the production decline in the Dodsland area
and an increase in production from the Pinto assets. The balance of the increase in production costs was
primarily attributable to inflationary increases in costs of services and supplies.
As discussed above, the Trust’s production comes primarily from low productivity wells. These wells generally
result in higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface leases,
power, and personnel costs are not variable with production volumes. The Trust is currently examining means
of reducing operating costs. The acquisition of Novitas should result in a minor reduction in operating costs per
BOE as Novitas’ 2004 operating costs averaged $9.81 per BOE. Operating costs in the $12 to $13 per BOE range
are expected for 2005. The high operating costs for the Trust are substantially offset by low royalty rates of
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approximately 10 percent, which is much lower than industry average for conventional production and results
in high cash net backs on a combined basis despite higher than average operating costs.
General and Administrative Expense
General and administrative expenses were $1,287,000 in 2004 compared to $1,372,000 in 2003. On a BOE
basis, general and administrative expenses in 2004 averaged $1.10 compared to $1.21 per BOE in 2003. The
Trust recorded only a net $20,000 of general and administrative costs in the fourth quarter of 2004 due
primarily to a $500,000 increase in fees charged to Novitas in 2004 (see below).
The Trust is managed internally. In addition, the Trust provides administrative services to Comaplex Minerals
Corp. (Comaplex) and Novitas, companies that share common directors and management. The fees for the
following services are representative of the fair value for the services rendered. Fees for these services are
deducted from the Trusts general and administrative expenses.
During 2004, the Trust received a management fee from Novitas for management services of $20,000 (2003
- $10,000) per month plus five percent of before tax income. In addition, the Trust accrued at year end
$500,000 representing compensation for additional engineering, accounting and management services
rendered to Novitas during 2004. Total receipts during 2004 were $271,000 (2003 - $120,000). Novitas also
paid administrative fees on a per well basis to the Trust for the administration of its oil and gas properties.
Total amount paid during 2004 was $192,000 (2003 - $148,000). The Trust received a management fee from
Comaplex of $240,000 (2003 - $210,000) for management services and office administration.
Interest Expense
Interest expense for the 2004 fiscal year of the Trust was $493,000 (2003 - $894,000). The decrease was
primarily due to the reduction in the Trust’s debt resulting from Bonterra’s public offering which closed on
June 30, 2004. The public offering raised $21,450,000 prior to issue costs of $1,178,000. The net proceeds of
$20,272,000 were used for capital expenditures and to retire bank debt.
Interest rate charges during the year on the outstanding debt averaged approximately 4.4 (2003 – 4.25)
percent. The Trust maintained an average outstanding debt balance of approximately $10,200,000 (2003 -
$20,600,000). Total debt as of December 31, 2004 represents less than two months of 2004 annual funds flow.
The Trust believes that maintaining debt at less than one year’s funds flow (calculated quarterly based on
annualized quarterly results) is an appropriate level to allow it to take advantage in the future of either
acquisition opportunities or to provide flexibility to develop its coal bed methane, shallow gas and infill oil
potential without requiring the issuance of trust units.
The Trust’s current bank agreements (each operating corporation has its own) provide for a combined
$36,900,000 (includes Novitas effective January 7, 2005) of available credit facility. The interest rate charged
on all non-BA facility borrowings is bank prime. The Trust’s banking arrangements allow it to use Bankers
Acceptances (BA’s) as part of its loan facility. Interest charges on BA’s are generally one third percent lower
than that charged on the general loan account. The Trust had $3,750,000 balance owing to Comaplex as of
December 31, 2003. The loan was repaid in the first half of 2004. The loan carried an interest rate of Royal
Bank of Canada prime less three quarters of a percent.
Unit Based Compensation
Effective January 1, 2004 the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”) section
3870, “Stock-based Compensation and Other Stock-based Payments”, retroactively with restatement of prior
periods. The recommendations required the Trust to record a compensation expense over the vesting period
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of its unit options based on the fair value of the unit options granted to employees, directors and consultants.
The fair value of options granted has been estimated using the Black-Scholes option pricing model, assuming
a weighted risk free interest rate of 2.87 (2003 – 3.75) percent, expected weighted average volatility of
30 (2003 – 32) percent, expected weighted average life of 3 (2003 – 3.6) years and an annual dividend rate
based on the distributions paid to the Unitholders during the year.
The result of applying the above total unit based compensation of $636,000, based on currently issued and
outstanding options, is required to be recorded over the years 2002 to 2006. Unit based compensation of
$236,000 in 2004, $211,000 in 2003 and $55,000 in 2002 has been recorded to date.
Depletion, Depreciation, Accretion and Dry Hole Costs
The Trust follows the successful efforts method of accounting for petroleum and natural gas exploration and
development costs. Under this method, the costs associated with dry holes are charged to operations. For
intangible capital costs that result in the addition of reserves, the Trust depletes its oil and natural gas
intangible assets using the unit-of-production basis by field. The Trust believes that the successful efforts
method of accounting provides a more accurate cost of the producing properties than the alternative measure
of full cost accounting.
For tangible assets such as well equipment, a life span of ten years is estimated and the related tangible costs
are depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating
depreciation over the life of reserves was determined to be more representative of actual costs of tangible
property. Given the Trusts long production life, wells generally require replacement of tangible assets more
than once during their life time. Most of the Trust’s wells have been producing since the 1960’s and are
expected to continue to produce for at least another twenty years.
Provisions are made for asset retirement obligations through the recognition of the fair value of obligations
associated with the retirement of tangible long-life assets being recorded in the period the asset is put into
use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are
statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value of the
liability through accretion charges which are included in depletion, depreciation and accretion expense. The
costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and
depreciation of the underlying asset.
At December 31, 2004, the estimated total undiscounted amount required to settle the asset retirement
obligations was $28,360,000. These obligations will be settled based on the useful lives of the underlying assets,
which extend up to 40 years into the future. This amount has been discounted using a credit-adjusted risk-free
interest rate of five percent. The discount rate is reviewed annually and adjusted if considered necessary. A
change in the rate would have a significant impact on the amount recorded for asset retirement obligations.
The calculation of the above requires an estimation of the amount of the Trust’s petroleum reserves by field.
These figures are calculated annually by an independent engineering firm and any adjustments are used to
recalculate depletion and asset retirement obligations. This calculation is to a large extent subjective. Reserve
adjustments are affected by economic assumptions as well as estimates of petroleum products in place and
methods of recovering those reserves. To the extent reserves are increased or decreased, depletion costs will vary.
For the fiscal year ending December 31, 2004, the Trust expensed $8,392,000 (2003 - $8,024,000) for the
above-described items. The increase of $368,000 over the 2003 balance is due primarily to dry hole costs.
During the fourth quarter, two gross (1.8 net) natural gas wells were considered to be dry holes. The costs of
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$480,000 related to the drilling of those wells have been expensed as dry hole costs and are included in the
above depletion figure.
The Trust currently has an estimated reserve life for its proved developed producing reserves of 12.4 (2003 –
11.8) years calculated using the Trust’s gross reserves (prior to allowance for royalties) based on the third
party engineering report dated December 31, 2004 and using fourth quarter 2004 average production rates.
When taking into consideration the Novitas acquisition, which was effective January 7, 2005, the Trust has
an estimated proved developed producing reserve life of approximately 12.1 years after adjusting for the
commencement of production from Novitas’ Peck Lake property which reserves were classified as proved non-
producing as of the September 30, 2004 Sproule Report.
Income Taxes
Taxable income earned within the Trust is required to be allocated to its Unitholders and as such the Trust
will not incur any current taxes. However, the Trust operates its oil and gas interests through its 100 percent
owned subsidiaries Bonterra Energy Corp. (Bonterra Corp.), Comstate Resources Ltd. (Comstate Ltd.), and
commencing in 2005, from Novitas. Both Bonterra Corp. and Comstate Ltd. pay the majority of their income
to the Trust through interest and royalty payments which are deductible for income tax purposes. For the
taxation periods ending prior to 2004, Bonterra Corp. and Comstate Ltd. both paid to the Trust sufficient
royalty and interest payments to eliminate all of their taxable income. During 2004, due to timing of capital
expenditures and other funds flow factors, Comstate Ltd. was unable to pay sufficient payments to the Trust
to eliminate all of its taxable income. Given the current development programs in place it is anticipated that
Comstate Ltd. will be able to obtain a full refund of the 2004 tax liability of $560,000 in 2005.
Future tax provision relates to the future taxes that exist within Bonterra Corp. and Comstate Ltd. The liability
on the balance sheet and the corresponding expense relates to temporary differences existing between
Bonterra Corp’s. and Comstate Ltd.’s book value of its assets and its remaining tax pools.
Net Earnings
The Trust is extremely pleased to report net earnings of $20,366,000 for the year ended December 31, 2004.
This is an increase of $6,350,000 over the Trusts 2003 net earnings of $14,016,000. The Trust recorded net
earnings per unit on a fully diluted basis in 2004 of $1.40 verses $1.04 in the 2003 year. This represents a
return on Unitholders’ equity of approximately 37.7 percent during the 2004 year based on year end
Unitholders’ equity.
The Trust has an average cost for its oil and gas assets of $4.65 per BOE of proved reserves ($5.11 per BOE
including the Novitas acquisition) resulting in a low depletion provision. This low cost combined with low
administration and interest expenses all contribute towards the significant net earnings.
Funds Flow from Operations
Funds flow from operations for the year ending December 31, 2004 was $29,606,000 compared to
$22,228,000 for the year ended December 31, 2003. Funds flow from operations is not a recognized measure
under Canadian generally accepted accounting principles (GAAP). The Trust believes that in addition to net
earnings, funds flow from operations is a useful supplemental measure as it demonstrates the Trust’s ability
to generate the cash necessary to make distributions, repay debt or fund future growth through capital
investment. Investors are cautioned, however, that this measure should not be construed as an indication of
the Trust’s performance. The Trust’s method of calculating this measure may differ from other issuers and
accordingly, it may not be comparable to that used by other issuers. For these purposes, the Trust defines
funds flow from operations as funds provided by operations before changes in non-cash operating working
capital items.
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The increase was primarily due to higher commodity prices and moderately higher production volumes. As
with all oil and gas producers the Trust’s funds flow is highly dependent on commodity prices. International
events and control of crude oil production by OPEC are likely factors that will result in 2005 commodity
prices being high and having a positive impact on funds flow.
The following reconciliation compares funds flow to the Trust’s net earnings as calculated according to
GAAP:
Three Months
Twelve Months
For the periods ended December 31
2004
2003
2004
2003
Net earnings for the period
Unit based compensation
Dry hole costs
$6,389,000
$3,502,000
$20,366,000
$14,016,000
41,000
480,000
31,000
-
236,00
480,000
211,000
-
Depletion, depreciation and accretion
1,846,000
2,406,000
7,912,000
8,024,000
Future income taxes
(78,000)
(125,000)
612,000
(23,000)
Funds flow from operations
$8,678,000
$5,814,000
$29,606,000
$22,228,000
Cash Netback
The following table illustrates the Trust’s cash netback:
$ per Barrel of Oil Equivalent (BOE)
Production volumes (BOE)
Gross production revenue
Royalties
Field operating
Field netback
General and administrative
Interest and taxes
Cash netback
2004
1,168,993
$ 45.83
(4.79)
(14.06)
26.98
(1.10)
(0.90)
2003
1,137,997
$ 38.18
(4.26)
(12.50)
21.42
(1.21)
(0.81)
$ 24.98
$ 19.40
Due to the Trust’s low royalty rate, the average increase of 20 percent in the gross production revenue resulted
in a 28.8 percent increase in the Trust’s cash net back.
Liquidity and Capital Resources
During 2004 the Trust participated in drilling 43 gross (27.2 net) wells at a total cost of $10,055,000. Of these
wells, 13 gross (.9 net) oil wells and 15 gross (13.6 net) natural gas wells were completed and on production
during 2004. In addition, five gross (4.2 net) oil wells will be on production by the end of the first quarter
2005. It is anticipated that the majority of the wells drilled in 2004 will be on production by the end of the
second quarter of 2005.
The Trust currently has plans to drill or recomplete 40 net shallow gas wells and 10 net infill oil wells in 2005.
Bonterra has been granted approval for reduced drill spacing units with respect to its CBM development.
Further infill drilling to enhance crude oil production is planned in several areas where the Trust has
non-operated interests. The Trust will participate with the operator of the properties on these prospects. Total
capital costs of approximately $18,000,000 for the currently planned development programs are anticipated
to be funded out of current cash flow and existing lines of credit.
The Trust is continuing in its efforts to acquire existing production through either property or corporate
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acquisitions. Acquisitions are being examined with the underlying consideration being to enchance value to
our existing Unitholders.
The Trust has no contractual obligations that last more than a year other than its office lease agreement which
is as follows:
Contract Obligations
Total
Less than
1 year
1 – 3
years
Office lease
$346,000
$260,000
$86,000
4 – 5
years
-
After
5 years
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At December 31, 2004 the Trust had debt of $3,861,000 (2003 – $21,830,000). The Trust through its operating
subsidiaries has bank revolving credit facilities totalling $32,000,000 at December 31, 2004 (December 31,
2003 - $32,000,000). The facilities have been increased to $36,900,000 upon the acquisition of Novitas. The
facilities carry an interest rate of Canadian chartered bank prime. As of December 31, 2004, the Trust had an
outstanding balance under the facilities of $3,550,000 (December 31, 2003 - $17,466,000).
The terms of the credit facilities provide that the loans are due on demand and are subject to annual review.
The credit facilities have no fixed payment requirements. The amount available for borrowing under the credit
facilities is reduced by the amount of outstanding letters of credit. As at December 31, 2004, the Trust had a
nominal amount of outstanding letters of credit. Collateral for the loans consists of a demand debenture
providing a first floating charge over all of the Trust’s assets, and a general security agreement.
Included in the Trust’s 2003 year end debt was a balance payable to Comaplex of $3,750,000. The loan was
repaid during the first half of 2004. The interest rate charged on the outstanding balance was bank prime less
three-quarters of a percent. The security provided by the Trust for the loan was that the Trust had agreed to
maintain a line of credit with its principal banker sufficient to repay the loan if demanded.
The Trust is authorized to issue an unlimited number of trust units without nominal or par value. The
following outlines changes in the Trust’s unit structure over the past two years.
Issued
Trust Units
2004
2003
Number
Amount
Number
Amount
Balance, beginning of year
13,521,405
$51,763,000
13,368,405
$50,198,000
Transfer of contributed surplus to
Unit capital
-
159,000
Issued pursuant to public offering
1,100,000
21,450,000
Unit issue costs for public offering
-
(1,178,000)
-
-
-
35,000
-
-
Issued pursuant to Trust unit
option plan
Balance, end of year
322,000
3,292,000
153,000
1,530,000
14,943,405
$75,486,000
13,521,405
$51,763,000
The Trust provides an option plan for its directors, officers, employees and consultants. Under the plan, the
Trust may grant options for up to 1,323,450 (2003 – 1,323,450) Trust units. The exercise price of each option
granted equals the market price of the Trust unit on the date of grant and the option’s maximum term is five
years. Options vest one-third each year for the first three years of the option term.
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A summary of the status of the Trust’s unit option plan as of December 31, 2004 and 2003, and changes
during the years ended on those dates is presented below:
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
2004
Options Weighted-Average
Options
Exercise Price
2003
Weighted-Average
Exercise Price
937,000
10,000
(322,000)
(60,000)
565,000
152,000
$10.96
15.60
10.22
10.00
$11.56
$11.52
963,000
211,000
(153,000)
(84,000)
937,000
140,000
$10.00
14.26
10.00
10.00
$10.96
$10.00
The following table summarizes information about unit options outstanding at December 31, 2004:
Range of
Exercise
Prices
Number
Outstanding
At 12/31/04
$9.70-$10.00
$15.20-$15.60
$9.70-$15.20
394,500
170,500
565,000
Options Outstanding
Weighted-Average
Remaining
Contractual Life
Options Exercisable
Number
Weighted-Average
Exercise Price
Exercisable Weighted-Average
At 12/31/04
Exercise Price
2.1 years
2.3 years
2.1 years
$ 9.98
15.22
$11.56
107,500
44,500
152,000
$10.00
15.20
$11.52
Business Prospects, Risks, and Outlooks
The resource industry operates with a great deal of risk. The most significant risks may come from oil and
natural gas price swings, the uncertainty of finding new reserves from drilling programs or acquisitions,
competition within the industry, and increasing environmental controls and regulations.
The prices received for crude oil are established by world market forces and for natural gas by forces within
North America. Fluctuations in pricing can have extremely positive or negative effects on the Trust’s cash
flow or in the value of its producing and non-producing oil and natural gas properties.
The Trust presently attempts to minimize these risks by pursuing both oil and natural gas activities and
operates its oil and natural gas interests in areas which have long life reserves, where it has the technical
expertise to enhance production, control operating costs and to increase margins of profit.
The Trust also maintains an active hedging program. Currently the Trust has forward sales agreements in
place for approximately 15 percent on a BOE basis of its estimated 2005 production. The Trust uses a
combination of fixed price swaps as well as no cost floor and collars to protect against commodity price
declines. During 2004 the Trust incurred a net loss on its hedging of $2,526,000 (2003 - $3,150,000).
Sensitivity Analysis
Sensitivity analysis, as estimated for 2005:
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Change of Canadian $0.01/U.S. $ exchange rate
Cash Flow
$1,152.000
$ 253,000
$ 568,000
Cash Flow
Per Unit (1)
$0.071
$0.016
$0.035
(1) In calculating the cash flow per unit, the units issued pursuant to the takeover of Novitas of 1,335,745 have been included along with the ending units
outstanding as of December 31, 2004.
Additional Information
Additional information relating to the Trust may be found on SEDAR.COM as well as on the Trust’s web site
at www.bonterraenergy.com.
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Management’s Responsibility for Financial Statements
The information provided in this report, including the financial statements, is the responsibility of
management. In the preparation of the statements, estimates are sometimes necessary to make a
determination of future values for certain assets or liabilities. Management believes such estimates
have been based on careful judgements and have been properly reflected in the accompanying
financial statements.
Management maintains a system of internal controls to provide reasonable assurance that the Trust’s
assets are safeguarded and to facilitate the preparation of relevant and timely information.
Deloitte & Touche LLP has been appointed by the Unitholders to serve as the Trust’s external auditors.
They have examined the financial statements and provided their auditors’ report. The audit committee
has reviewed these financial statements with management and the auditors, and has reported to the
Board of Directors. The Board of Directors has approved the financial statements as presented in this
annual report.
George F. Fink
President and CEO
Garth E. Schultz
Vice President, Finance and CFO
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Auditors’ Report
To the Unitholders of Bonterra Energy Income Trust:
We have audited the consolidated balance sheets of Bonterra Energy Income Trust as at December 31,
2004 and 2003 and the consolidated statements of Unitholders’ equity, operations and accumulated
income, and of cash flows for the years then ended. These consolidated financial statements are the
responsibility of the Trust’s management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian generally accepted auditing standards. Those
standards require that we plan and perform an audit to obtain reasonable assurance whether the
financial statements are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by management, as well as,
evaluating the overall financial statement presentation.
In our opinion, these consolidated financial statements present fairly, in all material respects, the
financial position of the Trust as at December 31, 2004 and 2003 and the results of its operations
and its cash flows for the years then ended in accordance with Canadian generally accepted
accounting principles.
Calgary, Alberta
March 15, 2005
Chartered Accountants
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Bonterra Energy Income Trust
Consolidated Balance Sheets
For the Years Ended December 31
Assets
Current
Accounts receivable
Crude oil inventory (Note 2)
Parts inventory
Prepaid expenses
Investment in related party (Note 3)
Abandonment deposit (Note 4)
Property and Equipment (Note 5)
2004
2003
(Restated See
Note 2)
$ 7,104,000
$
4,505,000
569,000
391,000
1,040,000
461,000
9,565,000
1,522,000
662,000
360,000
716,000
461,000
6,704,000
-
Petroleum and natural gas properties and related equipment
102,679,000
92,637,000
Accumulated depletion and depreciation
(28,777,000)
(21,504,000)
73,902,000
71,133,000
$ 84,989,000
$ 77,837,000
Liabilities
Current
Distribution payable
$ 2,690,000
$
1,623,000
Accounts payable and accrued liabilities
Debt (Note 6)
Future income tax liability (Note 7)
Asset retirement obligations (Note 2)
Unitholders’ Equity
Unit capital (Note 8)
Contributed surplus (Note 2)
Accumulated earnings
Accumulated cash distributions
On behalf of the Board:
11,962,000
3,861,000
18,513,000
997,000
11,419,000
30,929,000
75,486,000
307,000
51,688,000
5,803,000
21,830,000
29,256,000
384,000
11,214,000
40,854,000
51,763,000
231,000
31,322,000
(73,421,000)
(46,333,000)
54,060,000
36,983,000
$ 84,989,000
$ 77,837,000
Director
Director
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Bonterra Energy Income Trust
Consolidated Statements of Unitholders’ Equity
For the Years Ended December 31
2004
2003
(Restated See
Note 2)
Unitholders equity, beginning of year (Restated see Note 2)
$ 36,983,000
$ 42,003,000
Net earnings for the year
Net capital contributions (Note 8)
Unit option adjustment
Cash distributions
Unitholders’ Equity, End of Year
20,366,000
23,563,000
236,000
14,016,000
1,530,000
211,000
(27,088,000)
(20,777,000)
$ 54,060,000
$ 36,983,000
Bonterra Energy Income Trust
Consolidated Statements of Operations and Accumulated Income
For the Years Ended December 31
Revenue
Oil and gas sales, net of royalties
of $5,619,000 (2003 - $5,065,000)
Production costs
Alberta royalty tax credits
Interest and other
Expenses
General and administrative
Interest on debt
Unit based compensation (Note 2)
Dry hole costs
Depletion, depreciation and accretion
Earnings Before Income Taxes
Income taxes (recovery) (Note 7)
Current
Future
Net Earnings for the Year
Accumulated earnings at beginning of year (Restated see Note 2)
2004
2003
(Restated See
Note 2)
$ 47,966,000
$ 38,381,000
(16,438,000)
(14,110,000)
305,000
113,000
224,000
28,000
31,946,000
24,523,000
1,287,000
493,000
236,000
480,000
7,912,000
10,408,000
21,538,000
560,000
612,000
1,172,000
20,366,000
31,322,000
1,372,000
894,000
211,000
-
8,024,000
10,501,000
14,022,000
29,000
(23,000)
6,000
14,016,000
17,306,000
Accumulated Earnings at End of Year
Net Earnings Per Unit - Basic (Note 1)
Net Earnings Per Unit - Diluted (Note 1)
$ 51,688,000
$ 31,322,000
$
$
1.43
1.40
$
$
1.05
1.04
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Bonterra Energy Income Trust
Consolidated Statements of Cash Flows
For the Years Ended December 31
Operating Activities
Net earnings for the year
Items not affecting cash
Unit based compensation (Note 2)
Dry hole costs
Depletion, depreciation and accretion
Future income taxes
Changes in non-cash working capital
Accounts receivable
Crude oil inventory
Parts inventory
Prepaid expenses
Accounts payable and accrued liabilities
Financing Activities
Increase (decrease) in debt
Proceeds on issuance of units pursuant to public offering
Unit issue costs
Unit option proceeds
Unit distributions
Investing Activities
Property and equipment expenditures
Abandonment deposit (Note 4)
Changes in non-cash working capital
Accounts receivable
Accounts payable and accrued liabilities
Net cash inflow
Cash, beginning of year
Cash, End of Year
Cash Interest Paid
Cash Taxes Paid
2004
2003
(Restated See
Note 2)
$ 20,366,000
$ 14,016,000
236,000
480,000
7,912,000
612,000
211,000
-
8,024,000
(23,000)
29,606,000
22,228,000
(1,750,000)
80,000
(31,000)
(324,000)
2,236,000
211,000
368,000
(123,000)
(38,000)
(202,000)
(824,000)
(819,000)
29,817,000
21,409,000
(17,969,000)
2,200,000
21,450,000
(1,178,000)
3,292,000
(26,021,000)
(20,426,000)
-
-
1,530,000
(20,625,000)
(16,895,000)
(10,943,000)
(5,691,000)
(1,522,000)
-
(12,465,000)
(5,691,000)
(849,000)
3,923,000
3,074,000
-
1,177,000
1,177,000
(9,391,000)
(4,514,000)
-
-
-
493,000
17,000
$
$
$
-
-
-
894,000
12,000
$
$
$
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Bonterra Energy Income Trust
Notes to the Consolidated Financial Statements
For the Years Ended December 31
1. SIGNIFICANT ACCOUNTING POLICIES
Consolidation
These consolidated financial statements include the accounts of Bonterra Energy Income Trust (the “Trust”) and its
wholly owned subsidiaries Bonterra Energy Corp. and Comstate Resources Ltd.
Measurement Uncertainty
The amounts recorded for depletion and depreciation of petroleum and natural gas property and equipment and for
asset retirement obligations are based on estimates of petroleum and natural gas reserves and future costs. By their
nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future
periods could be material.
Inventories
Inventories consist of crude oil as well as materials and supplies which include tubing, rods, motors, pump jacks,
bases and miscellaneous parts used in the maintenance of the Trust’s tangible equipment. Both crude oil and
materials and supplies are valued at the lower of cost or net realizable value. Inventory cost for crude oil is
determined based on combined average per barrel operating costs, royalties and depletion and depreciation for the
year and net realizable value is determined based on sales price in the month preceding year end.
Investments
Investments are carried at the lower of cost and market value.
Property and Equipment
Petroleum and Natural Gas Properties and Related Equipment
The Trust follows the successful efforts method of accounting for petroleum and natural gas properties and related
equipment. Costs of acquiring unproved properties are capitalized. These costs are assessed at least annually and
when circumstances change, for impairment. When property is found to contain proved reserves as determined by
the Trusts engineers, the related net book value is depleted on the unit-of-production basis, calculated by field. The
costs of dry holes and abandoned properties are charged to operations. Geological costs, lease rentals and carrying
costs are charged to income as incurred. Costs of drilling exploratory and development wells that result in additions
to proved reserves are capitalized and depleted on the unit-of-production basis. Tangible equipment is depreciated
on a straight-line basis over ten years.
Furniture, Fixtures and Office Equipment
These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives.
Income Taxes
Income taxes are calculated using the liability method of accounting for income taxes. Under this method, income
tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the
amounts reported by the Trusts subsidiary companies in the consolidated financial statements of the Trust and their
respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on
future tax liabilities and assets is recognized in income in the period in which the change occurs.
The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed
or distributable to the Unitholders. As the Trust allocates all of its taxable income to the Unitholders in accordance
with the Trust Indenture, and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no
provision for income tax expense has been made in the Trust. However, the Trust’s subsidiaries are subject to
taxation on income which is not transferred to the Trust.
In the Trust structure, payments are made between the Trusts operating subsidiaries and the Trust which result in
the transferring of taxable income from the operating subsidiaries to individual Unitholders. These payments may
reduce future income tax liabilities previously recorded by the operating companies which would be recognized as
a recovery of income tax in the period incurred.
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Asset Retirement Obligations
The fair value of obligations associated with the retirement of tangible long-life assets are recorded in the period
the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations
recognized are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value
of the liability through accretion charges which are included in depletion, depreciation and accretion expense. The
costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and
depreciation of the underlying asset.
Trust-Unit-Based Compensation Plan
The Trust has a unit-based compensation plan, which is described in Note 8. The Trust records a compensation
expense over the vesting period based on the fair value of options granted to employees, directors and consultants.
Revenue Recognition
Revenues associated with sales of petroleum and natural gas are recorded when title passes to the customer.
Hedging
Derivative financial instruments are utilized to reduce commodity price risk on the Trust’s product sales. The Trust
does not enter into financial instruments for trading or speculative purposes.
The Trust’s policy is to formally designate each derivative financial instrument as a hedge of a specifically identified
product sale. The Trust assesses the derivative financial instruments for effectiveness as hedges, both at inception
and over the term of the instrument. The production volume in the instruments all match the production being
hedged.
The commodity price swap agreements are used as part of the Trust’s program to manage its product pricing. The
commodity price swap agreements involve the periodic exchange of payments and are recorded as adjustments of
net revenue. For the twelve months ended December 31, 2004 the Trust recorded a reduction to net revenue of
$2,526,000 (2003 - $3,150,000)
Joint Interest Operations
Significant portions of the Trust’s oil and gas operations are conducted with other parties and accordingly the
financial statements reflect only the Trust’s proportionate interest in such activities.
Net Earnings Per Unit
Basic earnings per unit are computed by dividing earnings by the weighted average number of units outstanding
during the year. Diluted per unit amounts reflect the potential dilution that could occur if options or warrants to
purchase trust units were exercised. The treasury stock method is used to determine the dilutive effect of trust unit
options and warrants, whereby proceeds from the exercise of trust unit options or other dilutive instruments are
assumed to be used to purchase trust units at the average market price during the period.
The number of trust units used to calculate diluted net earnings per unit for the year ended December 31, 2004 of
14,557,489 (2003 – 13,558,519) included the weighted average number of units outstanding of 14,217,550 (2003 –
13,394,363) plus 339,939 (2003 – 164,156) units related to the dilutive effect of unit options.
2.
CHANGES IN SIGNIFICANT ACCOUNTING POLICIES
The accounting policies and methods of application followed in the preparation of the 2004 annual financial
statements are the same as those followed in the preparation of the Trust’s 2003 annual financial statements except
for the following items:
•
Unit-based compensation plan
Effective January 1, 2004 the Trust adopted the Canadian Institute of Chartered Accountants (“CICA”)
section 3870, “Stock-based Compensation and Other Stock-based Payments”, retroactively with
restatement of prior periods. The recommendations require the Trust to record a compensation expense
over the vesting period based on the fair value of options granted to employees and directors.
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The change resulted in the following amendments to previously reported amounts for the twelve months
ended December 31, 2003 and balances as at December 31, 2003:
Unit based compensation
Unit capital
Contributed surplus (December 31, 2003)
Accumulated earnings (January 1, 2003)
Accumulated earnings (December 31, 2003)
•
Asset retirement obligations
As reported
$
-
51,137,000
-
17,841,000
31,879,000
$
Restated
211,000
51,172,000
231,000
17,786,000
31,613,000
Prior to January 1, 2004, the Trust accounted for its future site restoration liability on the unit-of-
production basis.
Effective January 1, 2004 the Trust retroactively adopted the CICA section 3110, “Asset Retirement
Obligations”. The new recommendations require that the recognition of the fair value of obligations
associated with the retirement of tangible long-life assets be recorded in the period the asset is put into
use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized
are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value
of the liability through accretion charges which are included in depletion, depreciation and accretion
expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with
the depletion and depreciation of the underlying asset.
The change resulted in the following amendments to previously reported amounts for the twelve months
ended December 31, 2003 and balances as at December 31, 2003:
Depletion, depreciation and accretion
$
8,203,000
$
8,024,000
As reported
Restated
Future income tax expense (recovery)
Unit capital
Accumulated earnings (January 1, 2003)
Accumulated earnings (December 31, 2003)
Petroleum and natural gas properties and related equipment
Accumulated depletion and depreciation
Asset retirement obligations
Future income tax liability
(134,000)
51,172,000
17,786,000
31,613,000
87,032,000
(19,545,000)
8,573,000
41,000
(23,000)
51,763,000
17,811,000
31,820,000
92,636,000
(21,366,000)
11,214,000
384,000
At December 31, 2004, the estimated total undiscounted amount required to settle the asset retirement
obligations was $28,360,000. These obligations will be settled based on the useful lives of the underlying
assets, which extend up to 40 years into the future. This amount has been discounted using a credit-
adjusted risk-free interest rate of 5 percent.
Changes to asset retirement obligations were as follows:
Asset retirement obligations, December 31, 2003
Adjustment to opening asset retirement obligation
Liabilities settled during the period
Accretion
Asset retirement obligations, December 31, 2004
•
Crude oil inventory
2004
$ 11,214,000
(7,000)
(352,000)
560,000
$ 11,419,000
Effective January 1, 2004 the Trust records its crude oil inventory at the lower of cost and net realizable
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value. Inventory cost is determined based on combined average per barrel operating costs, royalties and
depletion and depreciation for the period and net realizable value is determined based on sales price in
the month preceding period end. The change resulted in the following amendments to previously reported
amounts for the twelve months ended December 31, 2003 and balances as at December 31, 2003:
Oil and gas sales, net of royalties
$
38,377,000
$
38,381,000
As reported
Restated
Production costs
Accumulated earnings (January 1, 2003)
Accumulated earnings (December 31, 2003)
Accounts receivable
Crude oil inventory
14,227,000
17,811,000
31,820,000
5,530,000
-
14,110,000
17,306,000
31,322,000
4,505,000
662,000
Accumulated depletion and depreciation
(21,366,000)
(21,504,000)
•
Hedging relationships
The CICA published an amended Accounting Guideline 13, “Hedging Relationships”, effective January 1,
2004, to clarify circumstances in which hedge accounting is appropriate. All derivative instruments that
do not qualify as a hedge under the guideline, or are not properly designated as a hedge, will be recorded
on the balance sheet as either an asset or liability with changes in fair value recognized in earnings. The
Trust adopted the standard January 1, 2004 with no impact on the financial results.
The cumulative impact of the above described accounting changes to the year end December 31, 2003 was a
decrease in net earnings of $23,000 with no effect on Basic and Diluted Earnings per Trust Unit.
3.
INVESTMENT IN RELATED PARTY
The investment consists of 689,682 (December 31, 2003 – 689,682) common shares in Comaplex Minerals Corp
(Comaplex), a company with common directors and management. The investment is recorded at cost with the fair
market value based on the trading price of stock at December 31, 2004 of $2,414,000 (December 31, 2003 -
$2,931,000). The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment
represents less than a two percent ownership in the outstanding shares of Comaplex.
4.
ABANDONMENT DEPOSIT
The Trust under the Province of Alberta Regulations provided a cash deposit with the Alberta Energy and Utilities
Board for the future abandonment of specific wells. The deposit is refundable based on several conditions including
abandonment or reactivation of those inactive wells. The deposit bears interest at Canadian chartered bank prime
less approximately 2 percent.
5.
PROPERTY AND EQUIPMENT
2004
2003
Accumulated
Depletion and
Accumulated
Depletion and
Cost
Depreciation
Cost
Depreciation
Undeveloped land
$
308,000
$
-
$
186,000
$
-
Petroleum and natural gas properties
and related equipment
101,661,000
28,523,000
91,775,000
21,311,000
Furniture, equipment and other
710,000
254,000
676,000
193,000
$ 102,679,000
$
28,777,000
$
92,637,000 $
21,504,000
The Trust completed its acquisition of Novitas Energy Ltd. (Novitas) on January 7, 2005. Please refer to Note 13 for details.
6. DEBT
The Trust has a bank revolving credit facility of $32,000,000 at December 31, 2004 (2003 - $32,000,000). The terms
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of the credit facility provide that the loan is due on demand and is subject to annual review. The credit facility has
no fixed payment requirements. The amount available for borrowing under the credit facility is reduced by the
amount of outstanding letters of credit. Collateral for the loan consists of a demand debenture providing a first
floating charge over all of the Trust’s assets, and a general security agreement.
The credit facility carries an interest rate of Canadian chartered bank prime. As of December 31, 2004, the Trust had
an outstanding balance under the facility of $3,550,000 (2003 - $17,466,000). The Trust has classified borrowing
under its bank facilities as a current liability as required by guidance under the CICA’s Emerging Issues Committee
Abstract 122. It has been management’s experience that these types of loans which are required to be classified as
a current liability are seldom called by principal bankers as long as all the terms and conditions of the loan are
complied with. Cash interest paid during the year ended December 31, 2004 for this loan was $455,000 (2003 -
$636,000).
7.
INCOME TAXES
The Trust has recorded a future income tax liability related to assets and liabilities and related tax accounts held
through its 100 percent owned operating subsidiaries. The liability relates to the following temporary differences in
those subsidiaries:
Temporary differences related to assets and liabilities
of the subsidiary companies
Finance expense in corporate subsidiaries
Corporate Tax loss carry forwards in the subsidiary companies
2004
2003
$
1,636,000
$
1,141,000
(33,000)
(606,000)
(84,000)
(673,000)
$
997,000
$
384,000
Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial
income tax rates as follows:
Earnings before income taxes
Combined federal and provincial income tax rates
Income tax provision calculated using statutory tax rates
Increase (decrease) in income taxes resulting from:
Unit based compensation
Non-deductible crown royalties
Resource allowance
Trust income allocated to Unitholders
Others
2004
2003
$ 21,538,000
$
14,022,000
39.00%
8,400,000
92,000
1,317,000
(2,399,000)
(6,181,000)
(57,000)
$
1,172,000
$
41.14%
5,769,000
87,000
1,237,000
(1,998,000)
(5,051,000)
(38,000)
6,000
The Trust’s subsidiaries have the following tax pools, which may be used to reduce taxable income in future years,
limited to the applicable rates of utilization:
Undepreciated capital costs
Canadian oil and gas property expenses
Canadian development expenses
Canadian exploration expenses
Income tax losses
Finance expenses
Rate of Utilization %
Amount
20-100
$
5,431,000
10
30
100
100
20
1,600,000
7,260,000
65,000
1,779,000
98,000
$16,233,000
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The Trust has the following tax pools, which may be used to reduce future taxable income allocated to its Unitholders:
Canadian oil and gas property expenses
Finance expenses
8.
UNIT CAPITAL
Authorized
Rate of Utilization %
10
20
Amount
16,197,000
1,041,000
17,238,000
$
$
The Trust is authorized to issue an unlimited number of trust units without nominal or par value.
Issued
Trust Units
2004
2003
Number
Amount
Number
Amount
Balance, beginning of year
13,521,405
$ 51,763,000
13,368,405
$ 50,198,000
Transfer of contributed surplus to
Unit capital
-
159,000
Issued pursuant to public offering
1,100,000
21,450,000
Unit issue costs for public offering
-
(1,178,000)
-
-
-
35,000
-
-
Issued pursuant to Trust unit option plan
322,000
3,292,000
153,000
1,530,000
Balance, end of year
14,943,405
$ 75,486,000
13,521,405
$ 51,763,000
The Trust sold 1,100,000 units at a price of $19.50 pursuant to a public offering which closed on June 30, 2004.
Net proceeds after unit issue costs were $20,272,000.
The Trust provides an option plan for its directors, officers, employees and consultants. Under the plan, the Trust
may grant options for up to 1,323,450 (2003 – 1,323,450) trust units. The exercise price of each option granted
equals the market price of the trust unit on the date of grant and the option’s maximum term is five years. Options
vest one-third each year for the first three years of the option term.
A summary of the status of the Trust’s unit option plan as of December 31, 2004 and 2003, and changes during the
years ended on those dates is presented below:
Outstanding at beginning of year
Options granted
Options exercised
Options cancelled
Outstanding at end of year
Options exercisable at end of year
2004
Weighted-Average
Exercise Price
$10.96
15.60
10.22
10.00
$11.56
$11.52
Options
937,000
10,000
(322,000)
(60,000)
565,000
152,000
2003
Weighted-Average
Exercise Price
$10.00
14.26
10.00
10.00
$10.96
$10.00
Options
963,000
211,000
(153,000)
(84,000)
937,000
140,000
The following table summarizes information about unit options outstanding at December 31, 2004:
Options Outstanding
Options Exercisable
Range of
Exercise
Prices
$9.70-$10.00
$15.20-$15.60
$9.70-$15.20
Number
Weighted-Average
Number
Outstanding
At 12/31/04
394,500
170,500
565,000
Remaining
Weighted-Average
Exercisable Weighted-Average
Contractual Life
Exercise Price
At 12/31/04
Exercise Price
2.1 years
2.3 years
2.1 years
$ 9.98
15.22
$11.56
107,500
44,500
152,000
$10.00
15.20
$11.52
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The Trust records a compensation expense over the vesting period based on the fair value of options granted to
employees, directors and consultants. The fair value of options granted has been estimated using the Black-Scholes
option pricing model, assuming a weighted risk free interest rate of 2.87 (2003 – 3.75) percent, expected weighted
average volatility of 30 (2003 – 32) percent, expected weighted average life of 3 (2003 – 3.6) years and an annual
dividend rate based on the distributions paid to the Unitholders during the year.
9.
RELATED PARTY TRANSACTIONS
During 2004, the Trust provided a temporary operating loan of up to $1,500,000 to Novitas, a company with
common directors and management. The loan was repaid prior to December 31, 2004. The loan had an interest rate
of bank prime plus one-half percent. There was no security provided for the loan, however, the management
agreement in place between Novitas and the Trust, originally established as a 90 day automatic renewal, could not
be terminated as long as the loan remained outstanding. Interest paid on the loan during 2004 was $39,000.
During 2004, the Trust received a management fee from Novitas for management services of $20,000 (2003 -
$10,000) per month plus five percent of before tax income. In addition, the Trust accrued $500,000 representing
compensation for additional engineering, accounting and management services rendered during 2004. Total receipts
during 2004 were $272,000 (2003 - $120,000) and these receipts have been included as a recovery of general and
administrative expenses.
Novitas also paid administrative fees on a per well basis to the Trust for the administration of its oil and gas
properties. Total amount paid during 2004 was $192,000 (2003 - $148,000). This amount has also been recorded as
a recovery of general and administrative expenses.
The Trust received a management fee from Comaplex (see Note 3) of $240,000 (2003 - $210,000) for management
services and office administration. This cost has been included as a recovery in general and administrative expenses.
At December 31, 2003 the Trust owed Comaplex $3,750,000 which was repaid in the first half of 2004. Cash interest
paid during the twelve months ended December 31, 2004 for this loan was $37,000 (2003 - $257,000)
As at December 31, 2004, the Trust had an accounts receivable from Novitas for $503,000 and an accounts
receivable from Comaplex for $45,000 in respect of the above services.
The above charges all represent the fair value for the services rendered.
10. FINANCIAL INSTRUMENTS
Fair Values
The Trust’s financial instruments included in the balance sheet are comprised of accounts receivable and current
liabilities, including the revolving demand loan. The fair values of these financial instruments approximate their
carrying value due to the short-term maturity of those instruments, except borrowings under bank credit facilities
are for short periods with variable interest rates, thus, carrying values approximate fair value.
Credit Risk
Substantially all of the Trust’s accounts receivable are due from customers in the oil and gas industry and are subject
to normal industry credit risks. The carrying value of accounts receivable reflects management’s assessment of
associated credit risks.
Interest Rate Risk
The Trust’s bank debt is comprised of revolving loans at variable rates of interest, and as such, the Trust is exposed
to interest rate risk.
Commodity Price Risk
The nature of the Trust’s operations results in exposure to fluctuations in commodity prices and exchange
rates. The Trust monitors and when appropriate uses derivative financial instruments to manage its exposure
to these risks.
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11. COMMITMENTS, CONTINGENCIES AND GUARANTEES
The Trust entered into the following commodity hedging transactions in 2004 for a portion of its 2005 production:
Period of Agreement
Commodity
Volume per Day
Index
Price (Cdn.)
January 1, 2005 to March 31, 2005
April 1, 2005 to June 30, 2005
July 1, 2005 to September 30, 2005
October 1, 2005 to December 31, 2005
Crude Oil
Crude Oil
Crude Oil
Crude Oil
500 barrels
500 barrels
500 barrels
500 barrels
WTI
WTI
WTI
WTI
$43.08 per barrel
$48.52 per barrel
$50.02 per barrel
$55.60 per barrel
January 1, 2005 to March 31, 2005
Natural Gas
1,500 GJ’s
AECO
$6 per GJ floor
January 1, 2005 to March 31, 2005
Natural Gas
1,500 GJ’s
AECO
$5.70 per GJ floor
and $9.00 per GJ ceiling
and $9.50 per GJ ceiling
As at December 31, 2004 the mark to market value of the outstanding commodity hedging transactions was a net
liability of $299,000 to the Trust.
The Trust has no contractual obligations that last more than a year other than its office lease agreement which is
as follows:
Contract Obligations
Total
Less than 1 year
1 – 3 years
4 – 5 years
After 5 years
Office lease
$346,000
$260,000
$86,000
-
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12. SUBSEQUENT EVENT- COMMITMENTS
The Trust entered into the following commodity hedging transactions subsequent to December 31, 2004 for a
portion of its future production:
Period of Agreement
January 1, 2006 to March 31, 2006
April 1, 2005 to July 31, 2005
April 1, 2005 to October 31, 2005
Commodity
Crude Oil
Crude Oil
Natural Gas
Volume per Day
500 barrels
500 barrels
2,000 GJ’s
Index
WTI
WTI
AECO
November 1, 2005 to March 31, 2006
Natural Gas
1,500 GJ’s
AECO
Price (Cdn.)
$55.12 per barrel
$66.56 per barrel
$5.50 per GJ floor
and $7.75 per GJ ceiling
$6.00 per GJ floor
and $9.45 per G ceiling
13. SUBSEQUENT EVENT – ACQUISITION
The Trust entered into an agreement in 2004 to acquire Novitas (see Note 9). On January 6, 2005 in excess of 96
percent of the outstanding common shares of Novitas were tendered to the takeover offer. On January 7, 2005 the
Trust took up the shares and acquired the remaining outstanding shares through the compulsory acquisition
provisions of the Business Corporation Act of Alberta. Funding for the cash portion of the acquisition came from
the Trust’s available bank lines.
The acquisition will be accounted for the Novitas carrying values due to the related status of Novitas to the Trust.
The net assets of Novitas acquired were as follows:
Net Non-cash Working Capital
$(1,273,000)
Bank Indebtedness
Property and Equipment
Bank loan
Future Tax Liability
Asset Retirement Obligations
Trust Units Issued
Cash
Acquisition Costs
(155,000)
16,608,000
(4,443,000)
(3,089,000)
(1,198,000)
$ 6,450,000
$ 5,456,000
769,000
225,000
$ 6,450,000
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AR Cover 04 3/22/05 10:10 AM Page 3
Trust Profile
Bonterra Energy Income Trust. (TSX symbol – BNE.UN) is an energy income trust that develops and
produces oil and natural gas in the Provinces of Alberta and Saskatchewan.
The Trust’s business strategy is to strive to maximize Unitholder’s value by applying long-term growth
objectives. The Trust’s primary objective is to combine its oil and gas production technical strengths with
planned business strategies to generate above average results and returns for its Unitholders.
Contents
Highlights
Report to Unitholders
Review of Operations
Property Discussions
Management’s Discussion and Analysis
Management’s Responsibility for Financial Statements
Auditors’ Report
Consolidated Financial Statements
Notes to the Consolidated Financial Statements
Trust Information
Notice of Annual General Meeting
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IBC
The Annual General Meeting of Unitholders will be held on Monday, May 16, 2005, in the Nikiska Room,
Main Lobby Level, at the Westin Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m.
Forward-Looking Information
Certain information set forth in this document, including management’s assessment of Bonterra Energy Income Trust’s (“the Trust” or
“Bonterra”) future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject
to numerous risks and uncertainties, some of which are beyond Bonterra’s control, including the impact of general economic
conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental
risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market
volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used
in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as
such, undue reliance should not be placed on forward-looking statements. Bonterra’s actual results, performance or achievement could
differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given
that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits
Bonterra will derive therefrom. Bonterra disclaims any intention or obligation to update or revise any forward-looking statements,
whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not
represent fair market value of reserves.
Trust Information
Board of Directors
G.J. Drummond, Nassau, Bahamas
G.F. Fink, Calgary, Alberta
C.R. Jonsson, Vancouver, British Columbia
F. W. Woodward, Calgary, Alberta
Officers
G.F. Fink – President & Chief Executive Officer
R.M. Jarock – Chief Operating Officer
G.E. Schultz – Vice President, Finance,
Chief Financial Officer, & Secretary
Registrar & Transfer Agent
Olympia Trust Company, Calgary, Alberta
Auditors
Deloitte & Touche LLP, Calgary, Alberta
Solicitors
Parlee McLaws, Calgary, Alberta
Tupper, Jonsson & Yeadon,
Vancouver, British Columbia
Bankers
The Royal Bank of Canada, Calgary, Alberta
Stock Listing
The Toronto Stock Exchange, Toronto, Ontario
Trading symbol: BNE.UN
Web Site
www.bonterraenergy.com
Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488
AR Cover 04 3/22/05 10:10 AM Page 1
2004
901, 1015 – 4TH ST SW
CALGARY, ALBERTA T2R 1J4
Annual Report