COV Bonterra 5/13/02 6:45 PM Page 2
2001 ANNUAL REPORT
COV Bonterra 5/13/02 6:45 PM Page 3
TRUST PROFILE
Bonterra Energy Income Trust. (TSE 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 unitholders value by apply-
ing 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 our unitholders.
NOTICE OF ANNUAL MEETING
The Annual Meeting of Unitholders will
be held on Tuesday, June 18, 2002, in the
Barclay Room at the Westin Hotel, 320
TABLE OF CONTENTS
Highlights
Report to Unitholders
Review of Operations
Property Discussions
Management’s Discussion
and Analysis
Management’s Responsibility for
Financial Statements
Fourth Avenue S.W., Calgary, Alberta, at
Auditors’ Report
11:00 a.m. (Calgary time).
Consolidated Financial Statements
Notes to the Consolidated
Financial Statements
Trust Information
1
2
5
8
10
15
15
16
19
IBC
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HIGHLIGHTS
$
2001
For the Six Months Ended December 31, 2001
Financial ($000, except $ per unit)
Revenue – oil and gas (net of royalties)
Distributions per Unit
Cash Flow from Operations
Per Unit Diluted
Net Earnings
Per Unit Diluted
Capital Expenditures and Acquisitions
Outstanding Debt
Unitholders’ Equity
Units Outstanding (weighted average) (000’s)
Operations
Oil and Liquids (barrels per day)
Average Price ($ per barrel)
Natural Gas (MCF per day)
Average Price ($ per MCF)
Reserves (proven producing)
Oil and Liquids (barrels in 000’s)
Natural Gas (MCF in 000’s)
11,257
0.80
6,446
0.74
5,366
0.62
1,037
7,890
11,388
8,692
1,531
38.05
1,408
4.55
7,069
6,320
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REPORT TO UNITHOLDERS
Bonterra
Energy
Income
Trust
(“Bonterra”) is pleased to report its first
operational and financial results since
converting to a trust from a corporation on
July 1, 2001. The results are for the six-
month period ending December 31, 2001.
As previously announced, the trust was
mainly formed to provide a more favorable
environment for taxation and to provide a
monthly return to the Unitholders.
Operations
Bonterra’s production is ideally suited for a trust. Approximately 80 percent of its
production is mainly light, sweet gravity crude and liquids, and the remaining 20 percent
natural gas is sweet long-life production. The life index for the trust’s proven producing
reserves is approximately 12 years, which is significantly higher than most other trusts.
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.
Also, as previously announced when
Bonterra’s annual decline rate is approximately 6 percent.
Bonterra Energy Income Trust was formed,
the intent was to merge it with Comstate
Resources Income Trust. This merger was
completed on January 31, 2002.
Production volumes for the six-month period were slightly lower than the forecast
volumes mainly due to delays in being able to tie-in some gas production. It is
anticipated that all of these wells should be on production during the first half of 2002.
Financial
Bonterra’s distribution for the six-month period was $0.80 per Unit, of which 64.5 percent
is taxable and 35.5 percent is a return of capital. On an annualized basis, the distribution
generally exceeded a rate of return of 20 percent (dependent on Unit price), representing
one of the higher returns for trusts.
Rate of Return on Distributions
28.92
26.87
31.58
27.61
22.72
22.37
35%
30%
25%
20%
15%
10%
5%
0%
Rate of return based on average monthly price of units.
July
Aug
Sept
Oct
Nov
Dec
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Gross revenue from commodity sales of $11,257,000 for the six-month period was slightly lower than the forecast amount. The
reduction is due to lower commodity prices and slightly lower production volumes than forecast. Actual prices were $32.94 per barrel
of oil and natural gas liquids, and $3.46 per MCF for natural gas, compared to the price forecast provided by the trust’s independent
engineering firm of $40.32 per barrel and $7.27 per MCF. Actual prices received, including hedging gains, were $38.05 per barrel and
$4.55 per MCF.
At year-end Bonterra’s long-term debt was approximately $7,890,000, which is approximately 7 months cash flow on an annualized
basis. This debt to cash flow level is much lower than most other trust’s debt to cash flow levels.
Outlook
The objectives for the trust are to increase its production volumes in the future by developing its existing properties and by acquiring
additional production. The January 31, 2002 merger with Comstate Resources Income Trust will increase Bonterra’s production
volumes by approximately 80 percent. Management is aggressively pursuing further acquisitions and is hopeful that additional
production will be acquired in 2002.
In 2002 Bonterra will also be aggressively evaluating potential production from coal beds in the Pembina area of Alberta. The trust
will be testing a number of wells to determine production volumes of natural gas from the shallow coal beds to better assess the
economic potential for this type of production. Further information about results will be released on a timely basis.
The trust is optimistic that if commodity prices are reasonable, the trust should be able to continue to provide high returns and
additional capital appreciation. It should be noted that since Bonterra Energy Corp. (predecessor to the Trust) was incorporated and
listed publicly in mid 1998, for every $1.00 invested at that time, it is worth approximately $20.00 in March 2002.
Outlook
The Board of Directors of the operating company and management wish to thank the Unitholders for their continued support, and the
staff for the continued significant contribution made by them.
Submitted on behalf of the Board of Directors,
George F. Fink
President and Director
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REVIEW OF OPERATIONS
Reserves
The Trust engaged the services of an independent engineering firm to prepare a reserve
evaluation with an effective date of January 1, 2002. The reserves are located in the
Provinces of Alberta and Saskatchewan. The majority of the Company’s production is
comprised of light sweet crude, which results in higher oil prices, and better marketing
opportunities. The Company’s main oil producing areas are located in the Pembina area
of Alberta and Dodsland area of Saskatchewan. Oil and natural gas proven reserve
estimates at December 31, 2001, before royalties, are as follows:
July 1, 2001
Production
Drilling additions
Evaluation adjustments to reserves
December 31, 2001
Life index (years) - December 31, 2001
Crude Oil and Liquids
Natural Gas
Proven
Probable
Proven Probable
(MBbls)
(MMCF)
7,369
(282)
63
217
7,069
12.5
69
–
–
15
84
4,698
(259)
632
1,249
6,320
12.2
62
–
–
(26)
36
The reserve values in the following table, “Estimated Present Worth of Reserves”, are
based upon proved producing reserve estimates at December 31, 2001.
ESTIMATED PRESENT WORTH OF FUTURE NET PRODUCTION REVENUE
($ thousands)
$ Undiscounted
10%
15%
20%
Proven developed producing reserves
124,528
58,605
46,950
39,498
Probable reserves, risked at 50%
1,025
600
480
394
Discounted at the rate of
Proven and probable
reserves at December 31, 2001
125,553
59,205
47,430
39,892
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Commodity prices used in the above calculations of reserves are as follows:
Edmonton
Alberta
Year
Par Price
Index Plantgate
Propane
(Cdn $
(Cdn $
(Cdn $
Butane
(Cdn $
Pentane
(Cdn $
per barrel)
per MCF)
per barrel) per barrel) per barrel)
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
34.49
32.18
32.37
32.88
33.38
33.88
34.40
34.92
35.45
35.99
36.53
3.87
4.31
4.22
4.29
4.37
4.45
4.53
4.61
4.69
4.78
4.86
21.59
19.09
18.13
18.41
18.69
18.98
19.27
19.56
19.86
20.16
20.46
23.14
20.39
19.30
19.60
19.90
20.20
20.51
20.82
21.14
21.46
21.78
35.32
32.96
33.15
33.67
34.18
34.70
35.23
35.76
36.30
36.86
37.42
Crude oil, natural gas and liquid prices escalate at 1.5% per year thereafter.
Production
The following table provides a summary of production volumes from our main
producing areas.
Pembina, Alberta
Dodsland, Saskatchewan
Pinto, Saskatchewan
Land Holdings
Oil and NGL
(Bbls/day)
Natural Gas
(MCF/day)
2001
972
500
59
1,531
2001
986
354
68
1,408
The Trust’s holdings of petroleum and natural gas leases and rights are as follows:
Alberta
Saskatchewan
Gross Acres
Net Acres
36,034
29,630
65,664
28,080
17,768
45,848
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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 period:
Period ended December 31
Exploration and development costs
Pipeline projects
Seismic
Land costs
$
$
2001
964,200
292,900
10,100
62,300
Net petroleum and natural gas capital expenditures
$ 1,329,500
Drilling History
The following table summarizes the Trust’s gross and net drilling activity and success :
Development
Exploratory
Total
Gross
2
1
–
3
Net
2.00
.97
–
2.97
Gross
Net
Gross
Net
–
7
–
7
–
6
–
6
2
8
–
10
2.00
6.97
–
8.97
Crude Oil
Natural Gas
Dry
Total
Success rate
100%
100%
100%
100%
100%
100%
CUMULATIVE TOTAL RETURN ON $100 INVESTMENT
$2,000
$1,800
$1,600
$1,400
$1,200
$1,000
$800
$600
$400
$200
$0
July
1998
Dec
1998
Dec
1999
Dec
2000
Dec
2001
BONTERRA ENERGY CORP.
TSE 300 COMPOSITE INDEX
TSE OIL AND GAS PRODUCERS
Note 1: Includes the results of Bonterra Energy Corp. Prior to July 1, 2001
Note 2: Includes distributions of $0.80
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PROPERTY DISCUSSIONS
The Trust’s producing properties are located in the Pembina area of Alberta, the Dodsland
area in southwest Saskatchewan, the Pinto area in southeast Saskatchewan and
production has recently commenced from the Angling area in east central Alberta.
Bonterra continues to acquire exploration lands in the Pembina area of Alberta.
Pembina Area, Central Alberta
The Pembina field is the largest conventional oil field in Canada and our most significant
producing property. Our production is predominately predictable, long life, low decline
and high quality light oil from the Cardium formation which is located at a depth of
approximately 5,000 feet. Bonterra operates approximately 75 percent of its production in
this large core area which allows for significant operating efficiencies. The property
contains approximately 117 gross (98 net) operated producing wells with an 84 percent
average working interest and 189 gross (32 net) non-operated producing wells with an
approximate 17 percent average working interest.
Our large land holdings and strong infrastructure position provides a strong base to
exploit a range of low risk development and exploration opportunities. Even though the
Pembina area is considered a mature field it is proving to also be a significant area for the
potential development of additional oil and natural gas zones. The Trust continues to
increase it’s holding in the area to take advantage of these opportunities.
Bonterra has been able to increase oil production volumes and reserves through the
successful drilling of wells into the shallower Belly River formation. The Belly River
produces high quality light sweet oil from a depth of approximately 3,600 feet. There is
also the potential to increase production from the Cardium formation through infill drilling
in select areas of the field.
Bonterra has also been successful in increasing natural gas production and reserves by
drilling multi-zone shallow gas wells into the Edmonton and Paskapoo formations. The
company is targeting several productive sands that range in depth from 900 to 2,400 feet.
Bonterra will continue to build on our previous exploration success in the area and
develop these low cost shallow natural gas reserves.
Bonterra has been conducting tests to evaluate the feasibility of coal bed methane (CBM)
production with encouraging initial results. The Trust has extensive prospective land
holdings near existing operated infrastructure in the area. CBM has the potential to add
significant low risk production and reserves and the company is aggressively pursuing this
opportunity.
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Dodsland Area, Southwest Saskatchewan
The Dodsland properties produce light sweet gravity oil and solution gas from the Viking
formation at a depth of approximately 2,300 feet. Under terms of an existing agreement
Bonterra had an option to acquire additional production in this area. The option was
exercised in 2001 and an additional 66 gross wells (64 net) were acquired. Bonterra now
operates approximately 426 gross (374 net) wells with an average working interest of 88
percent.
This is low rate stable production so cost control is an important focus of our operating
strategy in this area. The Trust is continually reviewing different operating practices and
improved technology that may improve the profitability of the property. Bonterra does
not have an abandonment or reclamation liability for this property because under terms
of an agreement Bonterra has an option to transfer uneconomic wells to the previous
owner of the property.
Pinto Area, Southeast Saskatchewan
The Pinto property produces slightly sour gravity oil and solution gas from the Midale
formation. The Trust has an average working interest of approximately 95 percent in the
area. Bonterra continues to evaluate this area to determine if further optimization
programs may increase overall profitability for the property.
Angling Area, East Central Alberta
Angling is a new area that Bonterra has successfully advanced from an exploration
property to a producing property in early 2002. The 100 percent operated property
consists of sweet shallow gas production from the Colony formation. The Trust continues
to look to increase its’ holdings in the area and to find similar exploration opportunities.
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MANAGEMENT’S DISCUSSION AND ANALYSIS
This report 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 fiscal period ended December 31, 2001, together with the notes related thereto.
Production
The Trust’s average production of oil and natural gas liquids was 1,531 (1,553 during the last three months) barrels per day. The Trust’s
natural gas production averaged 1,408 (1,580 during the last three months) MCF per day for the six month period ending December
31, 2001. Production was approximately 250 MCF per day below forecast due to delays in tying in our Angling, Alberta production.
Subsequent to year end, this production was on stream at a rate of approximately 400 MCF per day.
Revenue
Gross revenue from petroleum and natural gas sales was $11,257,362. The average price received for crude oil and natural gas liquids
including hedging, was $38.05 per barrel and $4.55 per MCF of natural gas. Actual prices received during the period ending December
31, 2001 were $32.94 per barrel of oil and natural gas liquids and $3.46 per MCF for natural gas. The forecast prices, excluding hedging
adjustments, were $35.94 Cdn per barrel and $4.00 per MCF.
The Trust has hedging agreements in place from April 1, 2002 to October 31, 2003 for 1,000 GJ’s (approximately 950 MCF) per day of
natural gas at $3.77 Cdn. per GJ (approximately $3.97 per MCF), from May 1, 2002 to October 31, 2002 for 625 GJ’s (approximately 590
MCF) per day of natural gas at $4.30 Cdn. per GJ (approximately $4.53 per MCF) and for 600 barrels per day of crude oil at a price of
$37.97 Cdn. per barrel for the period April 1, 2002 to December 31, 2002.
Royalties
Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and Saskatchewan. During the period
the Trust paid $592,990 in Crown royalties and $119,333 in 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 6 percent and approximately 1 percent for other royalties. The Trust is eligible for Alberta Crown Royalty
rebates for Alberta production from a small amount of its purchased wells as well as on newly drilled wells.
Production Costs
Production costs totalled $4,097,781 in the six month period that the Trust operated in 2001. This was in line with forecasted operating
costs, however, on a BOE basis operating costs were $12.61 (using a 6 to 1 conversion) per BOE which is higher than both original and
revised forecasted amounts. The increase on a per barrel basis was due to delays in tying in lower cost natural gas production until
2002. Additional operating costs were incurred due to a major field maintenance program involving the repair and maintenance of
all Pembina area oil facilities during the months of October and November 2001.
General and Administrative Expense
General and administrative expenses excluding management fees were $244,803 or $0.75 per BOE. Total administrative costs
including the management fee of $323,500 were $568,303 or $1.75 per BOE. Both of these figures are in line with revised forecasted
numbers presented in the Trust’s September 30, 2001 quarterly report.
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The Trust has entered into a management agreement with Comstate Resources Ltd. (Comstate) to provide field operations,
management and general office services. Fees charged for field operations are charged on a per well basis. Fees associated with well
operations are charged to production costs as incurred. Fees for management and general office services consist of $30,000 per
month plus three percent of before tax net income. Effective February 1, 2002, Comstate became a wholly owned subsidiary of the
Trust and the Trust is no longer charged a management fee.
Interest Expense
Interest expense for the 2001 fiscal period of the Trust was $200,307. Interest expense was slightly higher than forecast due to
increases in loans resulting from larger capital expenditures for drilling additional gas wells than forecast as well as lower than forecast
revenues resulting in lower repayments of loans than anticipated.
Interest rate charges during the period on the outstanding debt averaged 4.85 percent. The Trust has the ability to use Bankers
Acceptances (BA’s) as part of its loan facility. Interest charges on BA’s are generally one half percent lower than that charged on the
general loan account.
Gain on Disposal of Property
On September 28, 2001, the Trust’s subsidiary, Novitas Energy Ltd. (Novitas), went public on the Canadian Venture Exchange (since
renamed TSX Venture Exchange) and ceased to be a subsidiary. With Novitas no longer being a subsidiary of the Trust the gain on
disposition of $294,206 from the sale of an oil and gas property from Bonterra to Novitas (original transaction of Novitas) had to be
adjusted. The gain represents the difference between the Trust’s book value of the property and the fair value of the property sold
to Novitas for cash proceeds of $650,000.
Depletion, Depreciation, Future Site Restoration and Dry Hole Costs
The Trust depletes its oil and natural gas intangible assets using the unit of production basis by field. 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.
Provisions are made for future site restoration based on management’s estimation of abandonment requirements using current costs
and amortized on a unit of production basis by field.
For the fiscal period ending December 31, 2001, the Trust expensed $1,797,984 for the above-described items.
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.
Income Taxes
The Trust is required to allocate all taxable income to its unitholders and as such will not incur any current taxes. The Trust operates
its oil and gas interests through its 100 percent owned subsidiary Bonterra Energy Corp. (Bonterra Corp.) With the restructuring into
an income trust, Bonterra Corp. pays the majority of its income to the Trust through interest and royalty payments which are
deductible for income tax purposes. For the period July 1 to December 31, 2001, Bonterra Corp. paid to the Trust sufficient royalty
and interest payments to eliminate all of its taxable income. The current tax amount represents adjustments to previous periods tax
accruals for Bonterra Corp.
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Future tax provision relates to the future taxes that exist within Bonterra Corp. The liability on the balance sheet and the
corresponding income recovery relates to temporary differences existing between Bonterra Corp’s. book value of its assets and its
remaining tax pools.
Net Earnings
The Trust is extremely pleased to report net earnings of $5,366,202 for its first six months of operations. This represents a return on
unit capital of 41.4 percent during the period. The Trust has an average cost for its oil and gas assets of $2.84 per BOE. The low
costs that result in low depletion and depreciation and low administration and interest expenses all contribute towards the significant
net earnings.
The Trust, effective February 1, 2002, merged with Comstate Resources Income Trust. Due to accounting rules affecting mergers, the
oil and gas assets of Comstate Resources Income Trust will be valued at the fair value on the date of merger. As a result, the Trust
will have a significantly higher average cost of its oil and gas assets for 2002. However, continued high energy prices should continue
to provide the Trust with significant net earnings.
Cash Flow From Operations
Cash flow from operations for the fiscal period ending December 31, 2001 was $6,446,134. The merger with Comstate Resources
Income Trust, anticipated operating cost reductions per BOE, increases in oil and natural gas prices, and increases in its production
volumes should substantially increase the Trusts 2002 cash flow.
Cash Netback
The following table illustrates the Trust’s cash netback:
$ per BOE
Production volumes (BOE)
Gross production revenue
Royalties
Field operating
Field netback
General and administrative
Management fees
Interest
Cash netback
$
$
2001
324,893
36.84
(2.19)
(12.61)
22.04
(0.75)
(1.00)
(0.62)
$
19.67
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Comparison to Forecast
REVENUE
Forecast
Actual
Difference
Oil and gas sales
$ 6,124,000
$ 5,717,000
$ (407,000)
Royalties
Other
(423,000)
(331,000)
16,000
51,000
92,000
35,000
TOTAL REVENUES
5,717,000
5,437,000
(280,000)
EXPENSES
Production costs
Management fee
General and administrative
Interest
TOTAL EXPENSES
CASH FLOW FROM OPERATIONS
DEPLETION, DEPRECIATION AND
FUTURE SITE RESTORATION
FUTURE INCOME TAXES
2,008,000
1,986,000
167,000
117,000
89,000
2,381,000
3,336,000
151,000
123,000
108,000
2,368,000
3,069,000
903,000
(213,000)
993,000
(110,000)
22,000
16,000
(6,000)
(19,000)
13,000
(267,000)
(90,000)
(103,000)
NET INCOME
$ 2,646,000
$ 2,186,000
$ (460,000)
The forecast figures are the revised forecasted amounts as stated in the Trust’s quarterly statements dated September 30, 2001.
Total oil and gas sales were lower than anticipated due primarily to oil prices averaging approximately $10 Cdn. lower than our
forecast. However, the Trust somewhat offset the lower oil prices by hedging 80 percent of its crude oil production leaving only 20
percent of its crude oil and its natural gas liquids at spot market prices during the period. In addition natural gas production volumes
were below our forecast averaging 1,580 MCF per day compared to forecasted production of 1,801 MCF per day. The 21.7 percent
decline in actual royalties from forecast compared to only 6.6 percent decline in revenues was due to the above discussed hedging
adjustments as royalties are calculated on well head prices.
Depletion, depreciation and future site restoration was higher due to larger claims on certain of our properties due to reallocation of
reserves resulting from our most recent reserve report dated January 1, 2002. Future income tax recovery declined by $103,000 due
to lower net income, resulting primarily from revenue being lower than forecast.
Liquidity and Capital Resources
During its first six months of operations, the Trust participated in drilling 10 gross (8.97 net) wells at a total cost of $1,037,085. Of these
wells, two (two net) oil wells and two (1.47 net) gas wells were completed and on production by December 31, 2001. Subsequent to
year end, three (2.5 net) gas wells drilled during the fiscal period of the Trust and three (three net) gas wells drilled prior to July 1,
2001 were placed on production. Current production from the wells placed on production subsequent to the Trusts fiscal year end is
approximately 1,000 MCF per day.
Three (three net) of the wells drilled in the Trusts fiscal period ending December 31, 2001 were not successful in producing from the
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zones originally drilled for but all have potential to produce coal bed methane. The Trust plans on evaluating the coal bed methane
zones during 2002.
At December 31, 2001 the Trust had bank debt of $7,889,737. The Trust’s credit facility at year-end consisted of a revolving line of
credit of $10,000,000 and carried an interest rate of one quarter percent above Canadian chartered bank prime. The Trust has issued
a $1,293,714 letter of credit to the Province of Alberta for future abandonment costs. Due to the outstanding letter of credit, the Trust’s
available borrowing under the above mentioned facility is $8,706,286. The letter of credit is reduced on a per well basis upon
notification of abandonment or reactivation of specified wells.
The credit facility allows for borrowings by means of Bankers Acceptances (BA’s). The effective interest rates of BA’s are generally half
a percentage point lower than that available under the normal credit facility. The Trust attempts to maximize the amount of its credit
facility used by financing with BA’s to reduce overall interest costs. 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.
At December 31, 2001, the Trust had no stock options issued under its Stock Option Plan. The option plan allowed for 869,223 options
to be issued. As a result of the merger with Comstate Resources Income Trust the maximum number of stock options that can be
issued has increased to 1,323,450 in 2002 (less than 10 percent of outstanding trust units).
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. The Trust may sometimes elect
to protect against price fluctuation by using commodity hedging. The Trust has hedged approximately 60 percent of its current oil
and gas production. Please see discussion under revenue and notes to financial statements for details. The Trust 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.
Sensitivity Analysis
Sensitivity analysis, which includes the impact of the February 1, 2002 merger with Comstate Resources Income Trust, as estimated
for 2002 follow:
U.S. $1.00 per barrel
Canadian $0.10 per MCF
Cash Flow
$1,136,000
$ 170,000
Change of Canadian $0.01/U.S. $ exchange rate
$ 377,000
Cash Flow
Per Unit
$0.085
$0.013
$0.028
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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 shareholders 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
AUDITORS’ REPORT
Garth E. Schultz
Vice President, Finance
To the Unitholders of Bonterra Energy Income Trust:
We have audited the balance sheet of Bonterra Energy Income Trust as at December 31, 2001 and the statements of unitholders’
equity, operations and accumulated income, cash available for distribution, and of cash flows for the period from formation, May 15,
2001, to December 31, 2001. These financial statements are the responsibility of the Trust’s management. Our responsibility is to
express an opinion on these financial statements based on our audit.
We conducted our audit 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 financial statements present fairly, in all material respects, the financial position of the Trust as at December 31,
2001 and the results of its operations and its cash flow for the period from formation, May 15, 2001, to December 31, 2001 in accordance
with Canadian generally accepted accounting principles.
Calgary, Alberta
March 22, 2002 Chartered Accountants (“Deloitte & Touche LLP”)
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Bonterra Energy Income Trust
CONSOLIDATED BALANCE SHEET
As at December 31, 2001 (See Note 1)
ASSETS
Current
Accounts receivable
Inventories
Prepaid expenses
$
$
2001
2,670,899
63,367
354,538
3,088,804
Property and equipment (Note 3)
Petroleum and natural gas properties and related equipment
28,909,019
Accumulated depletion and depreciation
LIABILITIES
Current
Bank indebtedness
Distributions payable
Accounts payable and accrued liabilities
Long-term debt (Note 4)
Future income tax liability (Note 6)
Future site restoration
Unitholders’ Equity
Unit capital (Note 5)
Accumulated income
Accumulated cash distributions
On behalf of the Board:
(5,845,831)
23,063,188
$
26,151,992
$
448,039
956,144
2,572,360
3,976,543
7,889,737
447,092
2,450,520
14,763,892
12,975,678
5,366,202
(6,953,780)
11,388,100
$
26,151,992
Director (“George F. Fink”)
Director (“F.W. Woodward”)
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CONSOLIDATED STATEMENT OF UNITHOLDERS’ EQUITY
For the Six Months Ended December 31, 2001 (See Note 1)
Unitholders’ equity, beginning of period (Note 1)
Net earnings for the period
Cash distributions
$
$
2001
12,975,678
5,366,202
(6,953,780)
Unitholders’ Equity, End of Period
$ 11,388,100
CONSOLIDATED STATEMENT OF OPERATIONS AND ACCUMULATED INCOME
For the Six Months Ended December 31, 2001 (See Note 1)
Revenue
Oil and gas sales, net of royalties of $712,323
Production costs
Alberta royalty tax credits
Interest and other
Expenses
General and administrative
Management fees
Interest on long-term debt
Cash Flow From Operations Before Current Taxes
Gain on disposal of property
Depletion, depreciation and future site restoration
Dry holes
Earnings Before Taxes
Income taxes (recovery) (Note 6)
Current
Future
Net Earnings for the Period
Accumulatd income at beginning of period
Accumulated Income at End of Period
Net Earnings Per Unit, Basic and Diluted (Note 2)
$
$
$
$
$
2001
11,257,362
(4,097,781)
34,877
14,768
7,209,226
244,803
323,500
200,307
768,610
6,440,616
294,206
(1,797,984)
(4,151)
(1,507,929)
4,932,687
(5,518)
(427,997)
(433,515)
5,366,202
–
5,366,202
0.62
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CONSOLIDATED STATEMENT OF CASH AVAILABLE FOR DISTRIBUTION
Bonterra Energy Income Trust
For the Six Months Ended December 31, 2001 (See Note 1)
$
2001
Cash flow from operations
$ 6,446,134
Cash provided by increase in long-term debt
Cash required for investing activities
Cash provided by working capital adjustments
Cash Distributions to Unitholders
863,274
(387,085)
31,457
6,953,780
Cash Distributions Per Unit, Basic and Diluted
$ 0.80
CONSOLIDATED STATEMENT OF CASH FLOWS
For the Six Months Ended December 31, 2001 (See Note 1)
Operating Activities
Net earnings for the period
Items not affecting cash
Gain on sale of property
Depletion, depreciation and future site restoration
Dry holes
Future income taxes
Cash Flow from Operations
Change in non-cash operating working capital items
Financing Activities
Increase in long-term debt
Unit distributions
Investing Activities
Property and equipment expenditures
Cash received on disposition of property
Net cash inflow (outflow)
Bank indebtedness, beginning of period
$
2001
$ 5,366,202
(294,206)
1,797,984
4,151
(427,997)
6,446,134
(1,372,726)
5,073,408
863,274
(5,997,636)
(5,134,362)
(1,037,085)
650,000
(387,085)
(448,039)
–
Bank Indebtedness, End of Period
$
(448,039)
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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Bonterra Energy Income Trust
Six Months Ended December 31, 2001 (See Note 1)
1. COMMENCEMENT OF TRUST
Bonterra Energy Income Trust was formed on May 15, 2001 to effect the arrangement
under the Business Corporations Act (Alberta) involving the exchange of the common
shares of Bonterra Energy Corp. on a four-for-one basis for units of Bonterra Energy
Income Trust. The shareholders of Bonterra Energy Corp. approved the arrangement on
June 27, 2001 and Bonterra Energy Income Trust commenced operations on July 1, 2001.
The financial statements represent operating results for the six month period July 1, 2001
to December 31, 2001. The arrangement is accounted for as a continuation through a
restructuring of Bonterra Energy Corp. As a result, the carrying values (see below) of the
assets and liabilities of Bonterra Energy Corp. are unaffected by the transaction.
Net Assets Acquired
Current Assets
Property and Equipment
Current Liabilities
Long-term Debt
Future Income Taxes
Future Site Restoration
$ 3,633,688
23,488,303
27,121,991
(4,158,064)
(7,026,463)
(877,857)
(2,083,929)
$ 12,975,678
2. SIGNIFICANT ACCOUNTING POLICIES
Consolidation
These consolidated financial statements include the accounts of the Trust and its wholly
owned subsidiary Bonterra Energy Corp. for the six months ended December 31, 2001.
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 and amortized on a straight-line basis over the lives of the related leases.
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,
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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
The Trust follows the liability method of accounting for income taxes under which the
income tax provision is based on the temporary differences in the accounts calculated
using income tax rates expected to apply in the year in which the temporary differences
will reverse.
Future Site Restoration
The Trust provides for future site restoration and abandonment costs over the estimated
production life of its property and equipment. Estimates of these amounts are based on
the anticipated method and extent of site restoration using current costs and in
accordance with existing legislation and industry practice. The annual charge is included
with depletion, depreciation and future site restoration.
Trust Unit-based Compensation Plan
The Trust has a trust-unit-based compensation plan as described in Note 5. No
compensation expense is recognized for the plan when trust units or options are issued.
Consideration paid on exercise of options is credited to unit capital.
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.
Inventories
Inventories consist of materials and supplies that are valued at the lower of cost or net
realizable value.
Net Earnings Per Unit
The Trust uses the treasury stock method of calculating earnings per unit and funds from
operations per unit in accordance with the new CICA Handbook Section 3500. Net
earnings per unit is calculated using the weighted average number of trust units
outstanding during the period, which was 8,692,226. There are no dilutive instruments
outstanding as of December 31, 2001 or during the period then ended.
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3. PROPERTY AND EQUIPMENT
Accumulated
Depletion and
Depreciation
Cost
Undeveloped Land
$ 461,215
$ –
Petroleum and natural gas properties
and related equipment
Furniture, equipment and other
28,422,237
25,567
5,834,969
10,862
$ 28,909,019
$ 5,845,831
During the period no general and administrative expenses were capitalized.
4. LONG-TERM DEBT
The Trust has a long-term bank revolving credit facility of $10,000,000 at December 31,
2001. The terms 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 one-quarter percent above
Canadian chartered bank prime. Cash interest paid during 2001 for this loan was $182,858.
The Trust is required under Province of Alberta Regulations to provide a letter of credit
in the amount of $1,293,714 to the Alberta Energy and Utilities Board for the future
abandonment of specified inactive wells. The letter of credit is reduced on a per well
basis if a well is reactivated or abandoned and the surface reclaimed.
5. UNIT CAPITAL
Authorized
The Trust is authorized to issue an unlimited number of trust units without nominal or par
value.
Issued
Trust Units
Number
Amount
Balance, beginning of period (Note 1)
Balance, end of period
8,692,226
8,692,226
$12,975,678
$12,975,678
The Trust provides an option plan for its directors, officers, employees and consultants.
Under the plan, the Trust may grant options for up to 869,223 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. As of December 31, 2001 no options have been issued.
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6. INCOME TAXES
The Trust has recorded a future income tax liability. The liability relates to the following
temporary differences:
Temporary differences related to assets and liabilities
$ 723,315
Finance expense charged to unitholders’ equity
Tax loss carry forward
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:
Non-deductible crown royalties
Resource allowance
Trust income allocated to unitholders
Non-taxable gain on disposal of property
Other
(103,263)
(172,960)
$ 447,092
$ 4,932,687
43.26%
2,133,880
293,072
(746,038)
(1,991,107)
(127,763)
4,441
$
(433,515)
The Trust and its subsidiary 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 exploration expenses
Tax loss
Finance expenses
Rate of
Draw down
%
Amount
20-100
$ 3,166,070
10
100
100
20
15,221,575
703,929
399,772
238,681
$19,730,027
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7. FINANCIAL INSTRUMENTS
The carrying value of the financial instruments of the Trust approximates their estimated fair values. Financial instruments include
accounts receivable, accounts payable and accrued liabilities, distributions payable, and long-term debt.
8. COMMITMENTS - FUTURE SALES AGREEMENTS
The Trust entered into the following commodity hedging transactions in 2001 for a portion of its 2002 production:
Period of Agreement
Commodity
Volume per day
Index
Price (Cdn.)
January 1 to January 31, 2002
February 1 to February 28, 2002
Crude Oil
Crude Oil
1,200 barrels
800 barrels
WTI
$42 per barrel
WTI
$42 per barrel
9. MANAGEMENT AGREEMENT
The Trust has entered into a management agreement with Comstate Resources Ltd. (Comstate), a company with common
management, to provide field operations, management and general office services. Fees charged for field operations are charged on
a per well basis. Total amount charged during the period was $394,020. This amount, net of amounts related to joint venture partner
interests, has been recorded in production costs.
Fees for management and general office services consist of $30,000 per month plus three percent of before tax net income. Total
amount paid during the period was $326,230 and has been included in general and administrative expenses.
Effective February 1, 2002, Comstate became a wholly owned subsidiary of the Trust and the Trust is no longer charged a management
fee.
10. SUBSEQUENT EVENT - MERGER
On December 17, 2001, the Trust announced its intention to combine with Comstate Resources Income Trust “Comstate Trust” by way
of merger whereby each unit holder of the Trust would receive 0.885 of a unit of Comstate Trust. The transaction will be accounted
for as a reverse takeover of Comstate Trust by the Trust as the former unitholders of the Trust will own greater than 50% of the units
of the new trust. This merger arrangement was approved by the unitholders of both Comstate Trust and the Trust on January 24, 2002
and was effective January 31, 2002.
As this transaction is to be accounted for as a reverse takeover, the assets and liabilities of the Trust will remain at their book values,
while the assets and liabilities of Comstate Trust will be recorded at their fair values on January 31, 2002. The net assets of Comstate
Trust acquired through this merger transaction are as follows:
Net working capital
Property and Equipment
Long-term Debt
Future Tax Liability
Future Site Restoration
$ 413,372
47,696,922
(6,750,000)
(314,658)
(4,320,792)
$ 36,724,844
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11. SUBSEQUENT EVENT- COMMITMENTS
The Trust entered into the following commodity hedging transactions subsequent to
December 31, 2001 for a portion of its future production:
Period of Agreement
Commodity
Volume per day
Index
Price (Cdn.)
April 1, 2002 to
October 31, 2003
Natural Gas
1,000GJ’s
AECO
$3.77 per GJ
May 1, 2002 to
October 31, 2002
Natural Gas
625GJ’s
AECO
$4.30 per GJ
April 1, 2002 to
December 31, 2002
Crude Oil
600 barrels
WTI
$37.97 per barrel
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CORPORATE INFORMATION
HEAD OFFICE
901, 1015 – Fourth Street SW
Calgary, Alberta T2R 1J4
REGISTRAR & TRANSFER AGENT
Olympia Trust Company, Calgary, Alberta
AUDITORS
PH 403.262.5307 FX 403.265.7488
Deloitte & Touche LLP, Calgary, Alberta
REGISTERED OFFICE
SOLICITORS
Suite 3400, 150 - 6th Avenue S.W.
Parlee McLaws, Calgary, Alberta
Calgary, Alberta T2P 3Y7
BOARD OF DIRECTORS
Tupper, Jonsson & Yeadon,
Vancouver, British Columbia
G.J. Drummond, Calgary, Alberta
BANKERS
G.F. Fink, Calgary, Alberta
The Royal Bank of Canada
C.R. Jonsson, Vancouver, British Columbia
Calgary, Alberta
F. W. Woodward, Calgary, Alberta
OFFICERS
G.F. Fink – President
STOCK LISTING
The Toronto Stock Exchange
Toronto, Ontario
R.M. Jarock – Operations Manager &
Trading symbol: BNE.UN
Vice President, Acquisitions
S.L. Safronovitch – Vice President
Operations
G.E. Schultz – Vice President, Finance &
Secretary
WEB SITE
www.bonterraenergy.com
COV Bonterra 5/13/02 6:45 PM Page 1
901, 1015 – FOURTH STREET SW, CALGARY, ALBERTA T2R 1J4