Bonterra Energy Corp.
Annual Report 2002

Plain-text annual report

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 1 2 3 6 8 14 14 15 18 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. 1 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 $18,357,000, which is approximately 11 months cash flow on an annualized basis. This debt to cash flow level is much lower than most other George F. Fink trust debt to cash flow levels. President, CEO and Director 2 Bonterra text 5/1/03 9:50 AM Page 3 REVIEW OF OPERATIONS Reserves The Trust engaged the services of an independent engineering firm to prepare a reserve evaluation with an effective date of January 1, 2003. The reserves are located in the Provinces of Alberta and Saskatchewan. The majority of the Trust’s production is comprised of light sweet crude, which results in higher oil prices, and better marketing opportunities. The Trust’s main oil producing areas are located in the Pembina area of Alberta and Dodsland area of Saskatchewan. Oil and natural gas established reserve estimates at December 31, 2002, before royalties, are as follows: December 31, 2001 Comstate Resources Income Trust Acquisition Production Other acquisitions Drilling additions Evaluation adjustments to reserves December 31, 2002 Life index (years) - December 31, 2002 Crude Oil and Liquids (MBbls) Natural Gas (MMCF) Proven Probable Proven Probable 84 374 – – – (39) 419 7,069 4,228 (899) 383 36 1,013 11,830 13.2 36 281 – – – 303 620 6,320 9,585 (1,565) 764 1,540 (1,366) 15,278 9.8 ESTIMATED PRESENT WORTH OF FUTURE NET PRODUCTION REVENUE ($ 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: 3 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 51 43 45 39 2,464 2,972 305 50 95 20 845 4,287 972 500 59 – – – 1,531 986 354 68 – – – 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 4 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 1 .13 – – 1 1.00 Development Net Gross – – 7.25 9 Exploratory Net – Gross – 2 1.13 9 7.25 Total Gross Net 1 10 Total Gross – 11 0.13 8.25 Net – 8.38 100% 100% 100% 100% 100% 100% Development Net Gross 2001 Exploratory Net Gross 2 2.00 – – 1 .97 Development 6 7 Exploratory – 3 – 2.97 – 7 – 6 Total Gross Net 2 8 – 10 Total 2.00 6.97 – 8.97 100% 100% 100% 100% 100% 100% 5 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 6 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. 7 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. 8 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 9 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 10 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 11 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. 12 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 April 1, 2003 to June 30, 2003 Crude Oil 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 WTI WTI WTI WTI AECO AECO AECO WTI WTI 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 13 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 14 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 Director 15 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 16 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) 17 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 18 $ 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 19 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 20 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 21 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 22 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 10 30 100 100 20 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 January 1, 2003 to March 31, 2003 April 1, 2003 to June 30, 2003 April 1, 2003 to June 30, 2003 July 1, 2003 to September 30, 2003 Crude Oil Crude Oil Crude Oil Crude Oil Crude Oil 900 barrels 400 barrels 400 barrels 600 barrels 600 barrels WTI WTI WTI WTI WTI $40.00 per barrel $45.10 per barrel $40.00 per barrel $40.05 per barrel $40.06 per barrel 23 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 AECO 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 600 barrels November 1, 2003 to March 31, 2004 Natural Gas 1,800 GJ’s WTI WTI 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 24 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 1 2 3 6 8 14 14 15 18 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 

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