Bonterra Energy Corp. Annual Report 2002

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FY2002 Annual Report · Bonterra Energy Corp.

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Bonterra 02 CV 5/1/03 9:36 AM Page 1

BONTERRA ENERGY INCOME TRUST, 901, 1015 – 4TH STREET SW, CALGARY, ALBERTA T2R 1J4

ANNUAL REPORT

Bonterra 02 CV 5/1/03 9:36 AM 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 applying long-term growth

objectives. The Trust’s primary objective is to com-

bine its oil and gas production technical strengths

with planned business strategies to generate above

average results and returns for our unitholders.

TABLE OF 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

IBC

NOTICE OF ANNUAL MEETING

The Annual Meeting of Unitholders will be held on Monday, June 16, 2003, in the Lakeview Endrooms at the

Westin Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m. (Calgary time).

TRUST INFORMATION

Head Office 901, 1015 – Fourth Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488

Board of Directors

G.J. Drummond, Calgary, Alberta

G.F. Fink, Calgary, Alberta

C.R. Jonsson, Vancouver, British Columbia

M.W. Pyke, Calgary, Alberta

F.W. Woodward, Calgary, Alberta

Officers

G.F. Fink – President & CEO

R.M. Jarock – Operations Manager & Vice

President, Corporate Development

S.L. Safronovitch – Vice President Operations

G.E. Schultz – Vice President, Finance & 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

Bonterra text 5/1/03 9:50 AM Page 1

HIGHLIGHTS

FINANCIAL ($000, except $ per unit)

Revenue - oil and gas (net of royalties)

Distributions per Unit

Cash Flow from Operations

Per Unit Fully Diluted

Net Earnings

Per Unit Fully 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 developed producing)

Oil and Liquids (barrels in 000’s)

Natural Gas (MCF in 000’s)

Note 1

2002

2001
(Note 1)

)

$ 36,424

$ 11,257

1.43

19,458

1.50

12,474

0.96

52,751

18,357

41,892

12,979

2,464

37.35

4,287

4.10

11,830

15,278

0.80

6,446

0.74

5,366

0.62

1,329

7,890

11,388

8,692

1,531

$ 38.05

1,408

4.55

7,069

6,320

Bonterra Energy Income Trust was formed on July 1, 2001. Comparative financial and operational figures listed

above represent operations from this date to December 31, 2001.

Bonterra text 5/1/03 9:50 AM Page 2

REPORT TO UNITHOLDERS
Bonterra Energy Income Trust (“Bonterra”) is pleased to report its operational and financial results for the year.

The Trust had a successful growth year and its annual distributions and capital appreciation resulted in a rate of

return to unitholders of 75 percent, far exceeding the return of most trusts and corporations.

Operations

Outlook

Bonterra’s production is ideally suited for a trust.

The objectives for the Trust are to increase its

Approximately 75 percent of its production is mainly

production volumes in the future by developing its

light, sweet gravity crude and liquids, and the

existing properties and by acquiring additional

remaining 25 percent natural gas is sweet long-life

production. The high commodity prices do make it

production. The life index for the Trust’s proven

more difficult to acquire properties at prices that will

producing reserves is approximately 12 years, which

benefit the Trust in the future, however, we still feel

is significantly higher than most other trusts. It should

that we will be successful in making some strategic

also be noted that Bonterra’s life index includes only

acquisitions in 2003.

proven producing reserves. Most other trusts life

In 2003 Bonterra will be aggressively evaluating

indexes include proven non-producing and probables

potential production from coal beds and other shallow

as well (established reserves).

natural gas horizons in the Pembina area of Alberta.

The long-life index allows the Trust to distribute a

The Trust will be testing a number of wells to

higher percentage of its cash flow to Unitholders

determine production volumes of natural gas from the

rather than using it for capital expenditures to

shallow coal beds to better assess the economic

maintain production volumes. Bonterra’s annual

potential for this type of production. Further

decline rate is approximately eight percent.

information about results will continue to be released

Production volumes for the 2002 year averaged 3,179

on a timely basis.

barrel of oil equivalents (BOE’s) per day compared to

The Trust is optimistic that if commodity prices are

1,766 BOE’s per day in 2001. The December 31, 2002

reasonable, the Trust should be able to continue to

exit production was approximately 3,400 BOE’s per

provide high returns and additional capital

day.
Financial

appreciation. It should be noted that since Bonterra

Energy Corp.

(predecessor to the Trust) was

Bonterra’s distribution for 2002 was $1.43 compared to

incorporated and listed publicly in mid 1998, for every

$0.80 for the six-month period ended December 31,

$1.00 invested at that time, it would now be worth

2001, of which 69.82 (2001 - 64.5) percent is taxable

approximately $21.24 plus the investor would have

and 30.18 (2001 - 35.5) percent is a return of capital.

received $5.20 in cash.

Gross revenue from commodity sales was $40,198,000

The Board of Directors of the operating company and

in 2002 compared to $11,970,000 for the preceding six

management wish to thank the unitholders for their

month period. Commodity prices were $37.35 per

continued support, and the staff for the continued

barrel of oil and natural gas liquids, and $4.10 per

significant contribution made by them.

MCF for natural gas.

Submitted on behalf of the Board of Directors,

At year-end Bonterra’s

long-term debt was

approximately $18,357,000, which is approximately

11 months cash flow on an annualized basis. This

debt to cash flow level is much lower than most other

George F. Fink

trust debt to cash flow levels.

President, CEO and Director

Bonterra text 5/1/03 9:50 AM Page 3

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, 2003. 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 oil producing areas are located in the Pembina area of Alberta and Dodsland area

of Saskatchewan. Oil and natural gas established reserve estimates at December 31, 2002, before royalties, are as

follows:

December 31, 2001

Comstate Resources Income Trust

Acquisition

Production

Other acquisitions

Drilling additions

Evaluation adjustments to reserves

December 31, 2002

Life index (years) - December 31, 2002

Crude Oil and Liquids (MBbls)

Natural Gas (MMCF)

Proven

Probable

Proven

Probable

374

–

(39)

419

7,069

4,228

(899)

383

1,013

11,830

13.2

281

–

303

620

6,320

9,585

(1,565)

764

1,540

(1,366)

15,278

9.8

ESTIMATED PRESENT WORTH OF FUTURE NET PRODUCTION REVENUE

($ thousands)

Undiscounted

Discounted at the rate of
15%

20%

10%

Proven developed producing reserves

Probable reserves, risked at 50%

222,946

10,645

105,571

1,722

85,335

1,032

72,432

692

Proven and probable reserves at December 31, 2002

233,591

107,293

86,367

73,124

Proven and probable reserves at December 31, 2001

125,553

59,205

47,430

39,892

Commodity prices used in the above calculations of reserves are as follows:

Bonterra text 5/1/03 9:50 AM Page 4

Year

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

Edmonton Par Price Alberta Index Plantgate
(Cdn $ per barrel)

(Cdn $ per MCF)

Propane
(Cdn $ per barrel)

Butane

Pentane

(Cdn $ per barrel) (Cdn $ per barrel)

38.43

34.82

32.22

32.78

33.90

34.42

35.58

36.13

36.69

37.26

37.83

38.42

5.72

5.21

4.60

4.27

4.42

4.48

4.67

4.75

4.84

4.94

5.03

5.12

21.53

19.50

18.05

18.36

18.99

19.28

19.93

20.24

20.55

20.87

21.19

21.52

24.35

22.06

20.42

20.77

21.48

21.81

22.54

22.89

23.24

23.60

23.97

24.34

39.36

35.66

33.00

33.57

34.72

35.25

36.44

37.00

37.57

38.16

38.75

39.35

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.

Oil and NGL (Bbls/day) Natural Gas (MCF/day) Oil and NGL (Bbls/day) Natural Gas (MCF/day)

2002

2001

Pembina, Alberta

Dodsland, Saskatchewan

Pinto, Saskatchewan

Redwater, Alberta

Midale, Saskatchewan

Other

Land Holdings

1,812

474

2,464

2,972

305

845

4,287

972

500

–

1,531

986

354

–

1,408

The Trust’s holdings of petroleum and natural gas leases and rights are as follows:

2002

2001

Gross Acres

Net Acres

Gross Acres

Net Acres

111,200

32,584

143,784

64,020

19,524

83,544

36,034

29,630

65,664

28,080

17,768

45,848

Alberta

Saskatchewan

Bonterra text 5/1/03 9:50 AM Page 5

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 periods:

2002

2001

Comstate Resources Income Trust acquisition

$ 47,697,000

Other acquisitions

Exploration and development costs

Pipeline projects

Seismic

Land costs

2,333,000

2,239,000

481,000

1,000

–

964,000

293,000

10,000

62,000

Net petroleum and natural gas capital expenditures

52,751,000

1,329,000

Drilling History

The following table summarizes the Trust’s gross and net drilling activity and success :

Crude Oil

Natural Gas

Dry
2001

Total

Success rate

Crude Oil

Natural Gas

Dry
2001

Total

Success rate

Development
Net
Gross

2002
Exploratory
Net

Gross

.13

–

1.00
Development
Net
Gross
–
–

7.25
9
Exploratory
Net
–

Gross
–

1.13

7.25

Total

Gross

Net

Total

Gross
–

0.13

8.25

Net
–

8.38

100%

Development
Net
Gross

2001
Exploratory
Net

Gross

2.00

–

.97
Development

6
7
Exploratory

–

2.97

–

Total

Gross

Net

–

Total

2.00

6.97

–

8.97

100%

Bonterra text 5/1/03 9:50 AM Page 6

Market Performance

CUMULATIVE TOTAL RETURN ON $100 INVESTMENT

Bonterra Energy Income Trust (notes 1 & 2)

JULY 1998

$100

DEC 1998

$245

$550

$900

DEC 1999

DEC 2000

DEC 2001

DEC 2002

$1,512

$2,644

Note 1:

Includes the results of Bonterra Energy Corp. prior to July 1, 2001

Note 2:

Includes distributions of $2.23 since becoming a trust.

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. Bonterra continues to acquire exploration lands

in the Pembina area of Alberta, is pursuing shallow gas exploration in Central Alberta 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

The Pembina field is the largest conventional oil field

gross (265.2 net) operated producing wells with an 86

in Canada and our most significant producing area.

percent average working interest and 135 gross (21.5

Our production is predominately predictable, long life,

net) non-operated producing wells with an

low decline and high quality light oil from the

approximate 16 percent average working interest.

Cardium formation that is located at a depth of

Our large land holdings and strong infrastructure

approximately 5,000

feet. Bonterra operates

position provides a strong base to exploit a range of

approximately 85 percent of its production in this large

low risk development and exploration opportunities.

core area which allows for significant operating

Even though the Pembina area is considered a mature

efficiencies. The property contains approximately 309

field it is proving to be a significant area for multi-zone

Bonterra text 5/1/03 9:50 AM Page 7

oil and natural gas exploration. The Trust has

Dodsland Area, Southwest Saskatchewan

managed to replace produced reserves in the area

The Dodsland properties produce light sweet gravity

through drilling as well as through key acquisitions.

oil and solution gas from the Viking formation at a

Bonterra is also producing from the Belly River

depth of approximately 2,300 feet. Bonterra now

formation. The Belly River produces high quality light

operates approximately 426 gross (374 net) wells with

sweet oil from a depth of approximately 3,600 feet.

an average working interest of 88 percent.

There is potential to increase production from the

This is low rate stable production so cost control and

Cardium and Belly River formations through infill

hedge programs are important focuses of our

drilling in select areas of the field. This program has

operating strategy in this area. The Trust is continually

been initiated on an experimental basis in 2003.

reviewing different operating practices and improved

Bonterra has been able to increase natural gas

technology that may improve the profitability of the

production and reserves by drilling multi-zone shallow

property. Bonterra does not have an abandonment or

gas wells into the Edmonton and Paskapoo

reclamation liability for this property because under

formations. The Trust is targeting several productive

terms of an agreement Bonterra has an option to

sands that range in depth from 900 to 2,400 feet.

transfer uneconomic wells to the previous owner of

Bonterra will continue to build on our previous

the property.

exploration success in the area and develop these low

Southeast Saskatchewan

cost shallow natural gas reserves.

The southeast properties produce slightly sour high

Bonterra has been conducting tests to evaluate the

gravity oil and solution gas from the Midale

feasibility of coal bed methane (CBM) production

formation. The Trust has an average working interest

with encouraging initial results. This year two wells

of approximately 86 percent in the area. Bonterra

were assigned conservative proved producing reserves

continues to evaluate this area to determine if further

by an independent engineering company. During 2003

optimization programs may

increase overall

the Trust plans to try to build on this initial success

profitability of the properties.

and expand these reserves. Bonterra has extensive

Other

prospective land holdings near existing operated

Bonterra has varying interests in other producing and

infrastructure in the area. CBM has the potential to

non-producing properties in various other areas of

add significant low risk production and reserves and

Alberta and Saskatchewan. Most of these properties

the Trust is aggressively pursuing this opportunity.

are

long

term producers and may provide

opportunities for increased interests in the future.

Bonterra text 5/1/03 9:50 AM Page 8

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 year ended December 31, 2002, together with the notes

related thereto.

Quarterly Comparisons

Financial ($000, except $ per unit)

4th

3rd

2002

2nd

1st

2001

2nd

1st

Revenue - oil and gas (net of royalties)

$ 9,781

$ 10,035

9,128

7,480

$ 5,386

$ 5,871

Cash Flow from Operations

Per Unit Diluted

Net Earnings

Per Unit Diluted

Capital Expenditures and Acquisitions

Outstanding Loans

Unitholders’ Equity

Operations

5,515

0.42

4,043

0.31

808

5,157

0.40

2,716

0.21

2,673

4,835

0.37

3,261

0.25

414

18,357

18,226

16,756

3,951

0.31

2,454

0.19

48,856

16,270

3,058

0.35

2,186

0.25

1372

3,388

0.39

3,180

0.37

(43)

7,890

7,299

41,892

44,266

46,362

48,181

11,388

13,548

Oil and Liquids (barrels per day)

2,571

2,600

Natural Gas (MCF per day)

4,605

4,953

2,341

3,787

2,175

3,159

1,502

1,548

1,560

1,268

Production

2002. This was accomplished without issuing any

The Trust’s 2002 average production of barrels of oil

additional trust units and only modestly increasing our

equivalent (BOE) was 3,179 (2001 - 1,766) barrels per

debt

level. Our exit production for 2002 is

day. Production of oil and natural gas liquids was

approximately 3,400 BOE’s per day.

2,464 (2001 - 1,531) barrels per day. The Trust’s

Revenue

natural gas production in 2002 averaged 4,287 (2001 -

Gross revenue from petroleum and natural gas sales

1,408) MCF per day. Production increases were

was $40,198,000 (2001 - $11,970,000). The average

predominantly due to the Trust’s merger with

price received for crude oil and natural gas liquids

Comstate Resources Income Trust on February 1,

including hedging, was $37.35 (2001 - $38.05) per

2002. The combined production rate at the date of

barrel and $4.10 (2001 - $4.55) per MCF of natural

merger was 3,123 BOE’s per day.

gas. Over 95 percent of

the Trust’s crude oil

Through a combination of our shallow gas drilling,

production consists of light sweet crude with nominal

acquisitions and pipeline tie-ins, the Trust was able not

quality and transportation adjustments. In addition,

only to replace its natural decline of approximately

our natural gas production consists primarily of dry

eight percent but also increase our production during

sweet natural gas.

Bonterra text 5/1/03 9:50 AM Page 9

Royalties

rates of approximately nine percent, which is much

Royalties paid by the Trust consist primarily of Crown

lower than industry average for conventional

royalties paid to the Provinces of Alberta and

production and results in high cash net backs on a

Saskatchewan. During the fiscal period ended

combined basis.

December 31, 2002 the Trust paid $2,995,000 (2001 -

General and Administrative Expense

$593,000) in Crown royalties and $778,000 (2001 -

General and administrative expenses were $1,298,000

$119,000) in freehold royalties, gross overriding

in 2002 compared to $568,000 in the 2001 six month

royalties and net carried interests. The majority of the

period. On a BOE basis, general and administrative

Trust’s wells are low productivity wells and therefore

expenses in 2002 averaged $1.12 per BOE compared to

have low Crown royalty rates. The Trust’s average

$1.75 per BOE in 2001.

Crown royalty rate is approximately seven percent and

The Trust had entered into a management agreement

approximately two percent for other royalties. The

with Comstate Resources Ltd.

to provide field

Trust is eligible for Alberta Crown Royalty rebates for

operations, management and general office services.

Alberta production from a small amount of

its

Fees charged for field operations were charged on a

purchased wells as well as on newly drilled wells.

per well basis. Fees associated with well operations

Production Costs

were charged to production costs as incurred. Fees

Production costs totalled $15,226,000 in 2002

for management and general office services consisted

compared to $4,098,000 in the six month period that

of $30,000 per month plus three percent of before tax

the Trust operated for in 2001. On a BOE basis, 2002

net income. Effective February 1, 2002, with the

operating costs were $13.12 compared to $12.61 for

merger of the Trust with Comstate Resources Income

the 2001 six month period. The increased costs on a

Trust, Comstate Resources Ltd. became a wholly

BOE basis are mainly due to more stringent gathering

owned subsidiary of the Trust and the Trust is no

system testing and maintenance required by the

longer charged a management fee.

Alberta Energy and Utilities Board, increases in

Interest Expense

municipal taxes, start-up costs of new wells and related

Interest expense for the 2002 fiscal year of the Trust

facility costs, facility maintenance, and increased costs

was $671,000 (2001 - $200,000). Interest rate charges

in non-operated properties.

during the period on the outstanding debt averaged

Management is currently examining means of

approximately four (2001 - 4.85) percent. The Trust

reducing operating costs. Operating costs in the $12 to

maintained an average outstanding debt balance of

$13 per BOE range are expected due to the number of

approximately $16,500,000.

low productivity oil wells the Trust owns expecially in

The Trust has the ability to use Bankers Acceptances

the Dodsland area of Saskatchewan. As the Trust

(BA’s) as part of its loan facility. Interest charges on

develops its shallow natural gas potential, the average

BA’s are generally one third percent lower than that

costs per BOE will decline. The high operating costs

charged on the general loan account. The Trust also

for the Trust are substantially offset by low royalty

has an $8,000,000 balance owing to Comaplex

Bonterra text 5/1/03 9:50 AM Page 10

Minerals Corp., a former subsidiary of Comstate

balance is due primarily to provisions on assets

Resources Ltd. The loan carries an interest rate of

acquired from Comstate Resources Income Trust as

Royal Bank of Canada prime less three quarters of a

well as a full year of operations.

percent.

The business combination of the Trust and Comstate

Gain on Disposal of Property

Resources Income Trust was treated as a purchase

On September 28, 2001, the Trust’s subsidiary, Novitas

which resulted in an increase of $34,625,000 to the

Energy Ltd. (Novitas), went public on the Canadian

carrying value of the assets of Comstate Resources

Venture Exchange (since renamed TSX Venture

Income Trust.

Exchange) and ceased to be a subsidiary. With

The Trust currently has an estimated reserve life of

Novitas no longer being a subsidiary of the Trust the

12.4 years based on a third party engineering report

gain on disposition of $294,000 from the sale of an oil

dated January 1, 2003. Therefore, depletion and

and gas property from Bonterra to Novitas (original

depreciation expense of the existing assets, excluding

transaction of Novitas) had to be adjusted. The gain

dry hole costs, will be less than 10 percent for 2003.

represents the difference between the Trust’s book

The Trust’s coal bed development program has the

value of the property and the fair value of the property

potential to increase the Trusts current reserve life as

sold to Novitas for cash proceeds of $650,000.

natural gas production from this type of formation

Depletion, Depreciation, Future Site Restoration

generally has a reserve life beyond 20 years.

and Dry Hole Costs

Income Taxes

The Trust follows the successful efforts method of

The Trust is required to allocate all taxable income to

accounting for petroleum and natural gas exploration

its unitholders and as such will not incur any current

and development costs. Under this method, the costs

taxes. The Trust operates its oil and gas interests

associated with dry holes are charged to operations.

through its 100 percent owned subsidiaries Bonterra

For intangible capital costs that result in the addition

Energy Corp.

(Bonterra Corp.) and Comstate

of reserves, the Trust depletes its oil and natural gas

Resources Ltd. (Comstate Ltd.) With the restructuring

intangible assets using the unit-of-production basis by

into an income trust, Bonterra Corp. and Comstate

field. For tangible assets such as well equipment, a

Ltd. pay the majority of their income to the Trust

life span of ten years is estimated and the related

through interest and royalty payments which are

tangible costs are depreciated at one tenth of original

deductible for income tax purposes. For the year

cost per year. Provisions are made for future site

ended December 31, 2002 and the period July 1 to

restoration based on management’s estimation of

December 31, 2001, Bonterra Corp. and Comstate

abandonment requirements using current costs and

Ltd. both paid to the Trust sufficient royalty and

amortized on a unit-of-production basis by field.

interest payments to eliminate all their taxable income.

For the fiscal year ending December 31, 2002, the

The current tax amount represents a recovery of

Trust expensed $7,570,000 for the above-described

previous period’s tax paid by Comstate Ltd.

items. The increase of $5,772,000 over the 2001

Future tax provision relates to the future taxes that

Bonterra text 5/1/03 9:50 AM Page 11

exist within Bonterra Corp. and Comstate Ltd. The

Field operating

liability on the balance sheet and the corresponding

Field netback

(13.12)

(12.61)

18.41

22.04

income recovery relates to temporary differences

General and administrative

(1.12)

(1.75)

existing between Bonterra Corp’s. and Comstate Ltd.’s

Interest

(0.58)

(0.62)

book value of its assets and its remaining tax pools.

Cash netback

16.71

$ 19.67

Net Earnings

The Trust is extremely pleased to report net earnings

of $12,474,000 for the fiscal year ended December 31,

2002. This was an increase of $7,108,000 over the

Trusts 2001 net income of $5,366,000. On a per unit

basis, the Trust recorded net earnings per unit in 2002

of $0.96 verses $0.62 in the 2001 fiscal period. This

represents a return on unitholders’ equity of

approximately 29.8 percent during the 2002 fiscal year

based on year end unitholders’ equity.

The Trust has an average cost for its oil and gas assets

of $4.82 per BOE of proven developed producing

Liquidity and Capital Resources

During the 2002 fiscal year the Trust participated in

drilling 11 gross (8.38 net) wells at a total cost of

$2,239,000. Of these wells, one (.13 net) oil wells and

8 (6.25 net) gas wells were completed and on

production by December 31, 2002. The remaining

two wells are waiting for pipeline tie-in which is

anticipated to occur prior to June 2003.

The Trust currently has plans to drill 30 (net of

approximately 20) shallow gas (including coal bed

methane) wells in 2003. Bonterra is currently seeking

approval for reduced drill spacing units in respect of

reserves resulting in low depletion and depreciation

our coal bed methane development. This approval

provisions. This combined with low administration

may result in increased drilling activity in 2003. The

and interest expenses all contribute towards the

currently planned drill program will be funded out of

significant net earnings.

Cash Flow from Operations

current cash flow and should at least replace our

anticipated 2003 natural production decline. Any

Cash flow from operations for the fiscal year ending

increases in the Trust’s capital expenditures program

December 31, 2002 was $19,458,000 compared to

will be subject to drilling results from existing

$6,446,000 for the six month fiscal period ended

programs and the Trust’s working capital position at

December 31, 2001. The increase was primarily due

the time.

to the acquisition of Comstate Resources Income

The Trust is continuing in its efforts to acquire existing

Trust and the full year of operations.

production through either property or corporate

Cash Netback

acquisitions. Acquisitions are being examined with

The following table illustrates the Trust’s cash netback:

the underlying consideration being enhancing value

$ per BOE

2002

2001

to our existing unitholders.

At December 31, 2002 the Trust had long-term debt

Production volumes (BOE)

1,160,152

324,893

of $18,357,000 (2001 - $7,890,000). The increase was

Gross production revenue

34.65

$ 36.84

due partially to the merger with Comstate Resources

Royalties

(3.12)

(2.19)

Income Trust as well as management’s decision to

Bonterra text 5/1/03 9:50 AM Page 12

increase the Trust’s debt leverage. The Trust still

indicated it will not request repayment within the next

maintains a debt to cash flow ratio of less than one

12 months.

year.

The Trust provides an option plan for its directors,

The Trust has a long-term bank revolving credit facility

officers, employees and consultants. Under the plan,

of $24,000,000 at December 31, 2002. The terms of

the Trust may grant options for up to 1,323,450 (2001

the credit facility provide that the loan is due on

- 869,223) trust units. The exercise price of each

demand and is subject to annual review. The credit

option granted equals the market price of the trust unit

facility has no fixed payment requirements. The

on the date of grant and the option’s maximum term

amount available for borrowing under the credit

is five years. Options vest one-third each year for the

facility is reduced by the amount of outstanding letters

first three years of the option term. On October 1,

of credit. Collateral for the loan consists of a demand

2002, the Trust issued 963,000 unit options to its

debenture providing a first floating charge over all of

directors, officers, employees and consultants. The

the Trust’s assets, and a general security agreement.

unit options were issued at the market value of the

Fourteen million dollars of the credit facility carries

Trust on October 1, 2002, which was $10 per unit and

an interest rate of Canadian chartered bank prime

expire January 31, 2007. The unit exercise price does

with the balance at one-quarter percent above prime.

not decline with the Trust’s return of capital.

As of December 31, 2002,

the Trust had an

Business Prospects, Risks, and Outlooks

outstanding balance under the facility of $10,357,000.

The resource industry operates with a great deal of

In 2001, the Trust was required under Province of

risk. The most significant risks may come from oil

Alberta Regulations to provide a letter of credit in the

and natural gas price swings, the uncertainty of finding

amount of $1,293,714 to the Alberta Energy and

new reserves from drilling programs or acquisitions,

Utilities Board for the future abandonment of specified

competition within the industry, and increasing

inactive wells.

In 2002, as a result of changes to the

environmental controls and regulations.

Provincial regulations, the Trust was no longer

The prices received for crude oil are established by

required to provide a letter of credit. The letter of

world market forces and for natural gas by forces

credit was cancelled during 2002.

within North America. Fluctuations in pricing can

Included in Bonterra’s long-term debt of $18,357,000

have extremely positive or negative effects on the

at December 31, 2002, is a balance payable of

Trust’s cash flow or in the value of its producing and

$8,000,000 to Comaplex Minerals Corp. (Comaplex).

non-producing oil and natural gas properties.

The interest rate is bank prime less three-quarters of a

The Trust presently attempts to minimize these risks

percent. There currently is no security provided by

by pursuing both oil and natural gas activities and

the Trust for the loan, but the Trust has agreed to

operates its oil and natural gas interests in areas which

maintain a line of credit with its principal banker

have long life reserves; where it has the technical

sufficient to repay the loan if demanded. The loan

expertise to enhance production, control operating

has been classified as long-term as Comaplex has

costs and to increase margins of profit.

Bonterra text 5/1/03 9:50 AM Page 13

The Trust also maintains an active hedging program.

declines. During 2002 the Trust incurred a net loss on

Currently the Trust has forward sales agreements in

its hedging of $928,000 as compared to a $1,706,000

place for approximately 45 percent on a BOE basis of

hedging gain in 2001. The following schedule outlines

its estimated 2003 production. The Trust uses a

the Trusts hedging position post December 31, 2002

combination of fixed price swaps as well as no cost

as of the printing of this report:

floors and collars to protect against commodity price

Period of Agreement

Commodity

Volume per day

Index

Price (Cdn.)

January 1, 2003 to March 31, 2003

Crude Oil

900 barrels

January 1, 2003 to March 31, 2003

Crude Oil

400 barrels

April 1, 2003 to June 30, 2003

Crude Oil

400 barrels

600 barrels

July 1, 2003 to September 30, 2003

Crude Oil

600 barrels

January 1, 2003 to October 31, 2003

Natural Gas

2,000 GJ’s

January 1, 2003 to March 31, 2003

Natural Gas

1,500 GJ’s

April 1, 2003 to October 31, 2003

Natural Gas

1,200 GJ’s

July 1, 2003 to September 30, 2003

Crude Oil

400 barrels

October 1, 2003 to December 31, 2003

Crude Oil

600 barrels

January 1, 2004 to March 31, 2004

Crude Oil

600 barrels

November 1, 2003 to March 31, 2004

Natural Gas

1,800 GJ’s

Sensitivity Analysis

Sensitivity analysis, as estimated for 2003 follow:

U.S. $1.00 per barrel

Canadian $0.10 per MCF

Change of Canadian $0.01/U.S. $ exchange rate

WTI

AECO

WTI

AECO

$40.00 per barrel

$45.10 per barrel

$40.00 per barrel

$40.05 per barrel

$40.06 per barrel

$3.77 per GJ

$5.76 per GJ

$5.82 per GJ

$45.00 per barrel

$40.00 per barrel

$41.00 per barrel

Floor of $5.00
and ceiling of
$9.05 per GJ

Cash Flow

Cash Flow
Per Unit

$ 944,000

$0.074

94,000

$0.007

$ 357,000

$0.027

Bonterra text 5/1/03 9:50 AM Page 14

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 & CEO

Garth E. Schultz

Vice President, Finance

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, 2002 and 2001

and the consolidated statements of unitholders’ equity, operations and accumulated income, and of cash flows for

the year ended December 31, 2002 and for the period from formation, May 15, 2001, to December 31, 2001. 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, 2002 and 2001 and the results of its operations and its cash flow for the year ended

December 31, 2002 and for the period from formation, May 15, 2001, to December 31, 2001 in accordance with

Canadian generally accepted accounting principles.

Calgary, Alberta

March 26, 2003 Chartered Accountants

Bonterra text 5/1/03 9:50 AM Page 15

Bonterra Energy Income Trust
CONSOLIDATED BALANCE SHEETS

As at December 31 (Note 1)

2002

2001

Assets

Current

Accounts receivable

Inventories

Prepaid expenses

Investments (at cost; quoted market value at

December 31, 2002 - $724,166)

Property and Equipment (Note 3)

Petroleum and natural gas properties and related equipment

Accumulated depletion and depreciation

Liabilities

Current

Bank indebtedness

Distributions payable

Accounts payable and accrued liabilities

Current portion of long-term debt (Note 4)

Long-term debt (Note 4)

Future income tax liability (Note 6)

Future site restoration

Unitholders’ Equity

Unit capital (Note 5)

Accumulated earnings

Accumulated cash distributions

On behalf of the Board:

5,895,518

$ 2,670,899

321,750

513,335

460,846

7,191,449

81,608,665

(12,382,836)

69,225,829

63,367

354,538

–

3,088,804

28,909,019

(5,845,831)

23,063,188

$ 76,417,278

$ 26,151,992

$ 1,272,866

448,039

1,470,525

5,449,301

10,357,155

18,549,847

8,000,000

175,478

7,800,058

34,525,383

49,607,447

17,840,667

(25,556,219)

41,891,895

956,144

2,572,360

7,889,737

11,866,280

–

447,092

2,450,520

14,763,892

12,975,678

5,366,202

(6,953,780)

11,388,100

$ 76,417,278

$ 26,151,992

Director

Bonterra text 5/1/03 9:50 AM Page 16

Bonterra Energy Income Trust
CONSOLIDATED STATEMENTS OF UNITHOLDERS’ EQUITY

For the Periods Ended December 31 (Note 1)

2002

2001

Unitholders equity, beginning of period (Note 1)

$ 11,388,100

$ 12,975,678

Net earnings for the period

Net capital contributions (Note 1)

Cash distributions

Unitholders’ Equity, End of Period

12,474,465

36,631,769

5,366,202

–

(18,602,439)

(6,953,780)

$ 41,891,895

$ 11,388,100

Bonterra Energy Income Trust
CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED INCOME

For the Periods Ended December 31 (Note 1)

2002

2001

Revenue

Oil and gas sales, net of royalties

of $3,773,298 (2001 - $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

Accumulated earnings at beginning of period

Accumulated Earnings at End of Period

$ 36,424,209

$ 11,257,362

(15,226,323)

(4,097,781)

158,112

42,421

34,877

14,768

21,398,419

7,209,226

1,243,880

54,000

670,933

1,968,813

19,429,606

–

(7,569,765)

–

(7,569,765)

244,803

323,500

200,307

768,610

6,440,616

294,206

(1,797,984)

(4,151)

(1,507,929)

11,859,841

4,932,687

(28,103)

(586,521)

(614,624)

(5,518)

(427,997)

(433,515)

$ 12,474,465

$ 5,366,202

5,366,202

–

$ 17,840,667

$ 5,366,202

Net Earnings Per Unit, Basic and Diluted (Note 2)

0.96

0.62

Bonterra text 5/1/03 9:50 AM Page 17

Bonterra Energy Income Trust
CONSOLIDATED STATEMENTS OF CASH FLOW

For the Periods Ended December 31 (Note 1)

2002

2001

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

Accounts receivable

Inventories

Prepaid expenses

Accounts payable and accrued liabilities

Financing Activities

Increase in long-term debt

Unit issue costs

Unit distributions payable upon merger

Unit distributions

Investing Activities

Property and equipment expenditures

Cash received on disposition of property

Bank indebtedness assumed upon arrangement (Note 1)

Bank indebtedness assumed upon merger (Note 1)

Net cash outflow

Bank indebtedness, beginning of period

Bank Indebtedness, End of Period

$ 12,474,465

$ 5,366,202

–

7,569,765

–

(586,521)

19,457,709

(583,485)

(132,411)

169,726

643,996

97,826

(294,206)

1,797,984

4,151

(427,997)

6,446,134

432,320

11,760

100,834

(1,859,340)

(1,314,426)

19,555,535

5,131,708

3,717,418

(93,075)

(794,606)

(18,088,056)

(15,258,319)

(5,006,521)

–

(115,522)

(5,122,043)

(824,827)

(448,039)

863,274

–

(5,997,636)

(5,134,362)

(1,037,085)

650,000

(58,300)

–

(445,385)

(448,039)

–

$ (1,272,866)

(448,039)

Bonterra text 5/1/03 9:50 AM Page 18

Bonterra Energy Income Trust
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

For the Periods Ended December 31, 2002 and 2001 (Note 1)

1. COMMENCEMENT OF TRUST AND BUSINESS COMBINATION

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

comparative figures disclosed in 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.

were 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

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 was accounted for as a reverse takeover of Comstate Trust by the Trust as the former

unitholders of the Trust own greater than 50% of the units of the new trust. The 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 accounted for as a reverse takeover, the assets and liabilities of the Trust remain at their book

values, while the assets and liabilities of Comstate Trust are recorded at their fair values on January 31, 2002. The

net assets of Comstate Trust acquired through this merger transaction were as follows:

Net Non-cash Working Capital

Bank Indebtedness

Investments

Property and Equipment

Long-term Debt

Future Tax Liability

Future Site Restoration

68,048

(115,522)

460,846

47,696,922

(6,750,000)

(314,658)

(4,320,792)

$ 36,724,844

Bonterra text 5/1/03 9:50 AM Page 19

Trust Units Issued

Unit Issue Costs

2. SIGNIFICANT ACCOUNTING POLICIES

Consolidation

$ 36,631,769

93,075

$ 36,724,844

These consolidated financial statements include the accounts of 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

future site restoration and reclamation 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 materials and supplies that are valued at the lower of cost or net realizable value.

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 and amortized on a straight-line basis over the

lives of the related leases. These costs are assessed annually for impairment. When property is found to contain

proved reserves as determined by the Trust’s 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

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

Bonterra text 5/1/03 9:50 AM Page 20

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, which is described in Note 5. No compensation expense is

recognized for these plans when unit options are issued to employees or directors at the prevailing market prices. Any

consideration paid by service providers on the exercise of theses options is recorded as unit capital. For options

issued after January 1, 2002, the fair values are determined and the impact on earnings if applicable is disclosed as

pro forma information.

Revenue Recognition

Petroleum and natural gas sales are recognized when the commodities are delivered to purchasers.

Hedging

The Trust uses derivative instruments to reduce its exposure to fluctuations in commodity prices and foreign exchange

rates. Gains and losses on these contracts, all of which constitute effective hedges, are recognized as a component

of oil and gas sales.

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 period. 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 period ended December 31, 2002

was 12,978,723 (2001 - 8,692,226). The number of units used to calculate diluted net earnings per unit discussed

above did not include 240,750 (2001 - Nil) of unit options on a weighted average basis, as the effect would be anti-

dilutive.

3. PROPERTY AND EQUIPMENT

2002

Accumulated
Depletion and
Depreciation

Cost

2001

Accumulated
Depletion and
Depreciation

Cost

Undeveloped Land

64,632

–

461,215

–

Petroleum and natural gas properties

and related equipment

80,907,617

12,276,863

28,422,237

5,834,969

Furniture, equipment and other

636,416

105,973

25,567

10,862

$ 81,608,665

$ 12,382,836

$ 28,909,019

5,845,831

Bonterra text 5/1/03 9:50 AM Page 21

During the period $35,803 (2001 - Nil) of general and administrative expenses were capitalized.

At December 31, 2002, the estimated future site restoration costs to be accrued over the life of the remaining proved

reserves are $18,944,765 (2001 - $17,658,528)

4. LONG-TERM DEBT

The Trust has a long-term bank revolving credit facility of $24,000,000 at December 31, 2002 (2001 - $10,000,000).

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.

Fourteen million dollars of the credit facility carries an interest rate of Canadian chartered bank prime with the

balance at one-quarter percent above prime. As of December 31, 2002, the Trust had an outstanding balance under

the facility of $10,357,155. The Trust has classified borrowing under its bank facilities as a current liability as

required by new guidance under the CICA’s Emerging Issues Committee Abstract 122. It has been management’s

experience that these types of loans which are now 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. The bank loan at

December 31, 2001 has been restated to conform to current presentation. Cash interest paid during the period ended

December 31, 2002 for this loan was $398,499 (six months ended December 31, 2001 - $182,858).

The Trust was 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. In 2002,

as a result of changes to the Provincial regulations, the Trust was no longer required to provide a letter of credit. The

letter of credit was cancelled during the second quarter.

As at December 31, 2002, the Trust has a balance payable of $8,000,000 to Comaplex Minerals Corp. (Comaplex)

a company with common management (see note 9). The interest rate is bank prime less three-quarters of a percent.

There currently is no security provided by the Trust for the loan, but the Trust has agreed to maintain a line of credit

with its principal banker sufficient to repay the loan if demanded. The loan has been reclassified as long-term as

Comaplex has indicated it will not request repayment within the next 12 months. Cash interest paid during the

twelve months ended December 31, 2002 for this loan was $269,346.

5. UNIT CAPITAL

Authorized

The Trust is authorized to issue an unlimited number of trust units without nominal or par value

Issued

Trust Units

2002

Number

Amount

Number

2001

Amount

Balance, beginning of period (Note 1)

8,692,226

$ 12,975,678

8,692,226

$ 12,975,678

Issued on Merger with Comstate

Resources Income Trust (Note 1)

4,676,179

36,631,769

–

Balance, end of period

13,368,405

$ 49,607,447

8,692,226

$ 12,975,678

Bonterra text 5/1/03 9:50 AM Page 22

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 (2001 - 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. On October 1, 2002, the Trust issued 963,000 unit options

to its directors, officers, employees and consultants. The unit options were issued at the market value of the Trust

on October 1, 2002, which was $10 per unit and expire January 31, 2007.

The Trust accounts for its stock based compensation plan using intrinsic values. Under this method no costs are

recognized in the financial statements for unit options granted to employees and directors when the options are

issued at prevailing market prices. For fiscal years beginning on or after January 1, 2002, Canadian generally accepted

accounting principles require disclosure of the impact on net earnings using the fair market value method for stock

options issued on or after January 1, 2002. If the fair value method had been used, the Trust’s net earnings and net

earnings per unit would not be significantly different from those reported. The fair value of options granted has

been estimated using the Black-Scholes option pricing model, assuming a risk free interest rate of 4.20%, expected

volatility of 25%, expected weighted average life of five years and an annual dividend rate based on the distributions

paid to the unitholders during the year.

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

801,425

723,315

2002

2001

Finance expense charged to unitholders’ equity

Tax loss carry forward

(150,160)

(475,787)

(103,263)

(172,960)

175,478

447,092

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 deemed disposition of subsidiary

Income tax rate reduction

Income tax recovery

Other

2002

2001

$ 11,859,841

$ 4,932,687

42.75%

5,070,082

1,391,837

(2,476,610)

(4,489,166)

–

(44,082)

(28,103)

(38,582)

43.26%

2,133,880

293,072

(746,038)

(1,991,107)

(127,763)

–

4,441

(614,624)

(433,515)

Bonterra text 5/1/03 9:50 AM Page 23

The Trust and its 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

7. FINANCIAL INSTRUMENTS

Fair Values

Rate of Utilization %

20-100

100

2002

Amount

4,956,396

21,593,507

325,110

1,334,947

1,124,702

551,951

$ 29,886,613

The Trust’s financial instruments included in the balance sheets are comprised of accounts receivable and current

liabilities, including the revolving demand loan and the loan payable to Comaplex. The fair values of these financial

instruments approximate their carrying value due to the short-term maturity of those instruments. Borrowings

under bank credit facilities and the Comaplex loan 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 which is comprised of a revolving loan and the Comaplex loan are at a variable rate 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.

8. COMMITMENTS

The Trust entered into the following commodity hedging transactions in 2002 for a portion of its 2003 production:

Period of Agreement

Commodity

Volume per day

Index

Price (Cdn.)

January 1, 2003 to March 31, 2003

April 1, 2003 to June 30, 2003

July 1, 2003 to September 30, 2003

Crude Oil

900 barrels

400 barrels

600 barrels

WTI

$40.00 per barrel

$45.10 per barrel

$40.00 per barrel

$40.05 per barrel

$40.06 per barrel

Bonterra text 5/1/03 9:50 AM Page 24

January 1, 2003 to October 31, 2003

Natural Gas

2,000 GJ’s

January 1, 2003 to March 31, 2003

Natural Gas

1,500 GJ’s

April 1, 2003 to October 31, 2003

Natural Gas

1,200 GJ’s

AECO

$3.77 per GJ

$5.76 per GJ

$5.82 per GJ

9. RELATED PARTY TRANSACTIONS

The Trust has guaranteed $3,000,000 of a loan to Novitas Energy Ltd. (Novitas), a former subsidiary of the Trust

and a company with common management. In consideration for the guarantee Novitas has entered into a

management agreement whereby the Trust will provide all management services on a fee for service basis.

During 2002, the Trust received a management fee from Novitas for management services of $5,000 per month plus

five percent of before tax income. Total receipts during 2002 were $68,000 (2001 - Nil) and 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 2002 was $128,500 (2001 - Nil). This amount has also been recorded as a recovery of

general and administrative expenses.

The Trust received a management fee from Comaplex of $110,000 (2001 - Nil) for management services and office

administration. This cost has been included as a recovery in general and administrative expenses.

10. MANAGEMENT AGREEMENT

Prior to its merger on February 1, 2002 with Comstate Trust, the Trust had entered into a management agreement

with Comstate Resources Ltd. (Comstate) a 100% owned subsidiary of Comstate Trust. Fees charged for field

operations were charged on a per well basis. Total amount charged during 2002 was $68,140 (2001 - $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 consisted of $30,000 per month plus three percent of before tax net

income. The total amount paid during the period was $54,000 (2001 - $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.

11. SUBSEQUENT EVENT – COMMITMENTS

The Trust entered into the following commodity hedging transactions subsequent to December 31, 2002 for a portion

of its future production:

Period of Agreement

Commodity

Volume per day

Index

Price (Cdn.)

July 1, 2003 to September 30, 2003

Crude Oil

October 1, 2003 to December 31, 2003

Crude Oil

January 1, 2004 to March 31, 2004

Crude Oil

400 barrels

600 barrels

November 1, 2003 to March 31, 2004

Natural Gas

1,800 GJ’s

WTI

AECO

$45.00 per barrel

$40.00 per barrel

$41.00 per barrel

Floor of $5.00
and ceiling of
$9.05 per GJ

Bonterra 02 CV 5/1/03 9:36 AM 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 applying long-term growth

objectives. The Trust’s primary objective is to com-

bine its oil and gas production technical strengths

with planned business strategies to generate above

average results and returns for our unitholders.

TABLE OF 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

IBC

NOTICE OF ANNUAL MEETING

The Annual Meeting of Unitholders will be held on Monday, June 16, 2003, in the Lakeview Endrooms at the

Westin Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m. (Calgary time).

TRUST INFORMATION

Head Office 901, 1015 – Fourth Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488

Board of Directors

G.J. Drummond, Calgary, Alberta

G.F. Fink, Calgary, Alberta

C.R. Jonsson, Vancouver, British Columbia

M.W. Pyke, Calgary, Alberta

F.W. Woodward, Calgary, Alberta

Officers

G.F. Fink – President & CEO

R.M. Jarock – Operations Manager & Vice

President, Corporate Development

S.L. Safronovitch – Vice President Operations

G.E. Schultz – Vice President, Finance & 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

Bonterra 02 CV 5/1/03 9:36 AM Page 1

BONTERRA ENERGY INCOME TRUST, 901, 1015 – 4TH STREET SW, CALGARY, ALBERTA T2R 1J4

ANNUAL REPORT