BNE Cover 2005 3/19/06 9:14 AM Page 1 901, 1015 – 4TH ST SW, CALGARY, ALBERTA T2R 1J4 2 0 0 5 A N N U A L R E P O R T BNE Cover 2005 3/19/06 9:14 AM Page 3 Bonterra Energy Income Trust. (TSX symbol – BNE.UN) is an energy income trust that develops and produces oil and natural gas in the Provinces of Alberta and Saskatchewan. The Trusts business strategy is to strive to maximize unitholders value by applying long-term growth objectives. The Trust’s primary objective is to combine its oil and gas production technical strengths with planned business strategies to generate above average results and returns for our unitholders. C O N T E N T S Highlights Report to Unitholders Review of Operations Property Discussions N O T I C E O F A N N U A L G E N E R A L M E E T I N G The Annual General Meeting of Unitholders will be held on Management’s Discussion and Analysis Management’s Responsibility for Financial Statements Wednesday, May 24, 2006, in the Nakiska room at the Westin Auditors’ Report Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m. Consolidated Financial Statements (Calgary time). Notes to the Consolidated Financial Statements Trust Information 1 2 4 8 10 20 20 21 24 IBC F O R W A R D - L O O K I N G I N F O R M A T I O N Certain information set forth in this document, including management’s assessment of Bonterra Energy Income Trust’s (“the Trust” or “Bonterra”) future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Bonterra’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonterra’s actual results, performance or achievement could differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Bonterra will derive therefrom. Bonterra disclaims any intention or obligation to update or revise any forward- looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not represent fair market value of reserves. T R U S T I N F O R M A T I O N Board of Directors G.J. Drummond, Nassau, Bahamas G.F. Fink, Calgary, Alberta C.R. Jonsson, Vancouver, British Columbia F. W. Woodward, Calgary, Alberta Officers G.F. Fink – President & Chief Executive Officer R.M. Jarock – Chief Operating Officer G.E. Schultz – Vice President, Finance, Chief Financial Officer & Secretary Registrar & Transfer Agent Olympia Trust Company, Calgary, Alberta Auditors Deloitte & Touche LLP, Calgary, Alberta Solicitors Borden Ladner Gervais LLP, 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 Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488 Web Site www.bonterraenergy.com Bonterra Energy 3/23/06 9:39 AM Page 1 H I G H L I G H T S Financial ($000, except $ per share) Revenue – oil and gas Distributions per Unit Funds Flow from Operations(1) Per Unit Basic Per Unit Fully Diluted Net Earnings Per Unit Basic Per Unit Fully Diluted Capital Expenditures and Acquisitions(2) Working Capital Deficiency Unitholders’ Equity Units Outstanding (000’s) Operations Oil and Liquids (barrels per day) Average Price ($ per barrel) Natural Gas (MCF per day) Average Price ($ per MCF) Total barrels per day (BOE per day) (3) Reserves Oil and Liquids (barrels in 000’s) Proved Developed Producing (Gross) (4) Proved (Gross) Proved plus Probable (Gross) Natural Gas (MCF in 000’s) Proved Developed Producing (Gross) Proved (Gross) Proved plus Probable (Gross) Reserve Life Index (Oil, liquids and natural gas @6:1)(5) Proved Developed Producing Proved Proved and Probable Reserves in BOE’s per Weighted Average Outstanding Unit Proved Developed Producing Proved Proved and Probable t s u r T e m o c n I y g r e n E a r r e t n o B 1 $ $ $ $ $ $ $ $ 2005 75,837 2.37 44,579 2.72 2.69 33,468 2.04 2.01 56,703 21,972 57,322 16,535 2,713 58.30 5,650 8.64 3,655 13,840 15,662 19,606 17,518 20,473 25,582 12.1 13.8 17.3 1.02 1.16 1.46 2004 53,585 1.88 29,606 2.08 2.03 20,366 1.43 1.40 10,595 8,948 54,060 14,943 2,361 47.30 4,996 6.81 3,194 11,956 12,832 16,084 17,021 18,288 21,762 12.4 13.3 16.5 1.04 1.12 1.39 (1) Funds flow from operations is not a recognized measure under GAAP. Management believes that in addition to net earnings, funds flow from operations is a useful supplemental measure as it demonstrates the Trust’s ability to generate the cash necessary to make trust distributions, repay debt or fund future growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Trust’s performance. The Trust’s method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For these purposes, the Trust defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items excluding gain on sale of property. (2) Capital expenditures and acquisitions include the purchase of Novitas Energy Ltd. (Novitas) on January 7, 2005. The Trust issued 1,335,753 units at a value of $25 per unit plus paid $769,000 in cash for all of the issued and outstanding common shares of Novitas. For accounting purposes the transaction was recorded at the cost of the Novitas’ assets and liabilities due to Novitas being considered a related party to the Trust. (3) BOE’s are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and as such may be misleading if used in isolation. (4) Gross reserves relate to the Trusts ownership of reserves before royalty interests. (5) The reserve life index is calculated by dividing the reserves (in BOE’s) by the annualized fourth quarter average production rate in BOE/d (2005 – 3,780, 2004 – 3,268). Bonterra Energy 3/23/06 9:39 AM Page 2 t s u r T e m o c n I y g r e n E a r r e t n o B 2 R E P O R T T O U N I T H O L D E R S Report to Unitholders Bonterra Energy Income Trust (“Bonterra” or the “Trust”) is pleased to report its operational and financial results for the year. It has been a year of growth and success for the Trust. Oil and gas reserves, distributions to Unitholders, net earnings, funds flow, and daily production all increased. There were only two major areas of concern that we encountered in 2005. Firstly, it was a difficult year from a weather perspective and most oil and gas entities could not drill, complete, or tie in new wells or service old wells because of the wet weather; and secondly, it has been difficult to get work done by the service industry due to the demand resulting from the accelerated activity in the oil and natural gas industry. Bonterra’s ability to continue to significantly increase its distributions on an annualized basis is of prime importance to the Trust. A continued above average return to the Trust’s investors is an objective that is important. The following graph illustrates the distribution growth during the most recent three year period. 0 0.5 1.0 1.5 2 2.5 2003 2004 2005 Operations 1.55 $/Unit 1.88 2.37 Bonterra has continued to focus on the development of its properties in the Pembina area, which is located in west central Alberta. Approximately 75 percent of the Trust’s production is from this field where production consists of light sweet gravity crude and liquids and sweet natural gas from the Cardium, Belly River, and shallow gas zones. The life index for the Trust’s proved reserves is 13.8 (2004 - 13.3) years, and the life index consisting of proved and probable reserves is 17.3 (2004 – 16.5) years. These reserve life figures are some of the longest (excluding oil sands) in the Trust and Corporate sectors. The long life index allows the Trust to distribute a higher percentage of its cash flow to Unitholders and for capital expenditures to increase production volumes rather than to maintain production volumes. Bonterra’s annual actual decline rate from existing properties is approximately 7 percent. Production volumes for 2005 averaged 3,655 barrels of oil equivalent (BOE) per day compared to 3,194 BOE per day in 2004. Drill programs during the fourth quarter should assist in increasing production volumes. At the 2005 year-end the Trust had a total of 13 (10.2 net) infill Cardium crude oil wells and 3 (2 net) shallow natural gas wells that had not been tied in and were not on production. The majority of these wells have been tied in and commenced production during the first quarter of 2006. Bonterra will be able to drill aggressively for many years into the future. If it drills approximately 50 wells per year, the Trust has an inventory of drill locations that exceeds 10 years. This inventory of drill locations is one of the highest in the industry and makes it unnecessary to make acquisitions of producing and non producing properties during periods when costs to make acquisitions are excessively high. Bonterra Energy 3/23/06 9:39 AM Page 3 Financial Bonterra’s distribution for 2005 was $2.37 compared to $1.88 for 2004. The Canadian taxable portion in 2005 was 86.05 (2004 – 58.51) percent and 13.95 (2004 – 41.49) percent is a return of capital. With respect to cash distributions paid during the year to U.S. individual Unitholders, 9.3 percent is a return of capital and 90.7 percent should be reported as qualities dividends. High commodity prices generally make it more difficult for Trusts to keep the taxable portion at lower levels. Revenue from commodity sales was $75,837,000 in 2005 compared to $53,585,000 in 2004. Commodity prices were $58.30 (2004 - $47.30) per barrel of oil and natural gas liquids and $8.64 (2004 - $6.81) per MCF for natural gas. At year-end Bonterra’s net working capital deficit was $21,972,000 (2004 - $8,948,000) when classifying all debt as current liabilities. This debt level represents approximately 5 months of debt to the fourth quarter of 2005 average monthly funds flow. This is a low ratio considering most of Bonterra’s capital expenditures in 2005 were incurred in the fourth quarter and did not generate any revenue in 2005 to use to pay down debt incurred for drilling and completions. The Trust’s objective is to have debt levels that do t s u r T e m o c n I y g r e n E a r r e t n o B 3 not exceed one year’s funds flow. Outlook The objectives for the Trust are to increase its production volumes and reserves by drilling its large inventory of drill locations in a conservative and timely manner. Subject to reasonably consistent commodity prices, this should enable the Trust to annually increase its distributions on a per Unit basis. Drilling will primarily be conducted in the Pembina field in the Cardium and shallow gas zones including some wells in the Ardley coal beds and experimentation completions in the Horseshoe Canyon coal beds. The Trust is optimistic with regard to its drill programs and its ability to continue to provide high returns and additional appreciation of its Unit price. It should be noted that since Bonterra Energy Corp. (predecessor to the Trust) was incorporated and listed publicly in 1998, for every $100 invested at that time, a Unit holder that held continuously from that date to February 28, 2006, would have received $1,902.55 in distributions and have Trust Units worth $5,852.06. The Board of Directors of the operating company and management wish to thank the Unitholders for their continued loyal support and advice, and also wish to thank the staff for its continued loyalty and the large contribution that is made on a continuous basis towards the success of the Trust. Submitted on behalf of the Board of Directors George F. Fink President, CEO, and Director Bonterra Energy 3/23/06 9:39 AM Page 4 t s u r T e m o c n I y g r e n E a r r e t n o B 4 R E V I E W O F O P E R A T I O N S Reserves The Trust engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective date of December 31, 2005. The reserves are located in the Provinces of Alberta and Saskatchewan. The Trust’s main oil producing areas are located in the Pembina area of Alberta, and the Dodsland and Shaunavon areas of Saskatchewan. The gross reserve figure for the following charts represents the Trust’s ownership interest before royalties and the net figure is after deductions for royalties. Summary of Oil and Gas Reserves as of December 31, 2005 (Forecast Prices and Costs) RESERVE CATEGORY PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE Light and Medium Oil Gross (Mbbl) Net (Mbbl) Reserves Natural Gas Gross (MMcf) Net (MMcf) Natural Gas Liquids Gross (Mbbl) Net (Mbbl) 13,070 357 1,462 14,889 3,758 18,647 12,407 325 1,335 14,067 3,580 17,647 17,518 1,257 1,698 20,473 5,109 25,582 13,160 978 1,188 15,326 3,780 19,106 770 3 - 773 186 959 549 2 - 551 133 684 Reconciliation of Trust Gross Reserves by Principal Product Type (Forecast Prices and Costs) Light and Medium Oil Natural Gas December 31, 2004 Extension Improved recovery Technical revisions Discoveries Acquisitions Dispositions Economic factors Production December 31, 2005 (Mbbl) (Mbbl) (MMcf) (MMcf) Gross Proved Gross Probable Gross Proved Gross Proved Gross Probable Gross Proved Plus Probable (MMcf) 21,761 8 2,804 (842) 329 3,002 (134) 716 (2,063) 25,582 Plus Probable (Mbbl) 14,477 – 2,442 (342) – 1,893 – 1,171 (993) 18,648 18,288 8 2,085 (481) 214 1,854 (52) 620 (2,063) 20,473 11,541 – 1,806 (42) – 1,569 – 1,008 (993) 14,889 2,936 – 637 (300) – 324 – 163 – 3,759 3,473 – 719 (361) 115 1,148 (82) 97 – 5,109 Summary of Net Present Values of Future Net Revenue as of December 31, 2005 (Forecast Prices and Costs) (M$) RESERVE CATEGORY PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED PROBABLE TOTAL PROVED PLUS PROBABLE 0 499,982 20,664 23,212 543,858 161,186 705,044 Net Present Value of Future Net Revenue Before and After Income Taxes Discounted at (%/year) 10 15 5 330,464 16,340 16,902 363,706 68,687 432,393 251,662 14,120 12,056 277,838 40,309 318,147 207,080 12,639 8,286 228,005 27,876 255,881 20 178,336 11,504 5,317 195,157 21,033 216,190 Bonterra Energy 3/23/06 9:39 AM Page 5 t s u r T e m o c n I y g r e n E a r r e t n o B 5 Commodity prices used in the above calculations of reserves are as follows: Year Edmonton Par Price 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 (Cdn $ per barrel) 70.07 70.99 62.73 57.53 54.65 55.47 56.31 57.16 58.02 58.89 59.78 Alberta Gas Reference Price Plantgate (Cdn $ per MCF) Propane Butane Pentane (Cdn $ per barrel) (Cdn $ per barrel) (Cdn $ per barrel) 11.37 10.63 8.76 7.69 7.39 7.52 7.63 7.77 7.90 8.04 8.18 39.25 39.76 35.14 32.22 30.61 31.07 31.54 32.01 32.50 32.99 33.48 47.01 47.62 42.08 38.59 36.66 37.21 37.77 38.34 38.92 39.51 40.10 71.77 72.71 64.25 58.92 55.97 56.81 57.67 58.54 59.42 60.31 61.22 Crude oil, natural gas and liquid prices escalate at various rates thereafter. The following cautionary statements are specifically required by NI 51-101 • It should not be assumed that the estimates of future net revenue presented in the above tables represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. • Disclosure provided herein in respect of BOE’s may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6mcf:1bbl has been used in all cases in this disclosure. This BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. • Estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenues for all properties due to the effects of aggregation. Production The following table provides a summary of production volumes from the Trust’s main producing areas: Pembina, Alberta Shaunavon, Saskatchewan Dodsland, Saskatchewan Peck Lake, Saskatchewan Pinto, Saskatchewan Redwater, Alberta Midale, Saskatchewan Other 2005 Oil and NGL (Bbls/day) 1,767 363 302 - 73 37 42 129 2,713 Natural Gas (MCF/day) 4,290 - 151 541 86 57 14 511 5,650 2004 Oil and NGL (Bbls/day) Natural Gas (MCF/day) 1,729 - 388 - 59 42 42 101 2,361 4,231 - 207 - 50 53 18 437 4,996 Bonterra Energy 3/23/06 9:39 AM Page 6 t s u r T e m o c n I y g r e n E a r r e t n o B 6 Land Holdings The Trust’s holdings of petroleum and natural gas leases and rights are as follows: Alberta Saskatchewan 2005 2004 Gross Acres 114,657 63,136 177,793 Net Acres 68,098 48,538 116,636 Gross Acres 113,697 32,584 146,281 Net Acres 67,159 19,524 86,683 Petroleum and Natural Gas Capital Expenditures The following table summarizes petroleum and natural gas capital expenditures incurred by the Trust on acquisitions, land, seismic, exploration and development drilling and production facilities for the years ended December 31: Acquisitions Exploration and development costs Pipeline projects Land costs Net petroleum and natural gas capital expenditures 2005 $ 40,852,000 15,810,000 15,000 26,000 $ 56,703,000 2004 $ - 10,057,000 302,000 236,000 $ 10,595,000 Drilling History The following table summarizes the Trust’s gross and net drilling activity and success: Crude Oil Natural Gas Dry Total Success rate Crude Oil Natural Gas Dry Total Success rate Crude Oil Natural Gas Dry Total Success rate Development 2005 Exploratory Total Gross 42 6 - 48 100% Net 15.0 3.5 - 18.5 100% Net - - - - - Gross 42 6 - 48 100% Gross - - - - - 2004 Development Exploratory Total Gross 19 19 4 42 90.5% Net 5.8 16.6 3.8 26.2 85.5% Net - 1 - 1 100% Gross 19 20 4 43 90.7% Gross - 1 - 1 100% 2003 Development Exploratory Total Gross 31 3 - 34 100% Net 3.3 3.0 - 6.3 100% Gross - 6 - 6 100% Net - 5.8 - 5.8 100% Gross 31 9 - 40 100% Net 15.0 3.5 - 18.5 100% Net 5.8 17.6 3.8 27.2 86.0% Net 3.3 8.8 - 12.1 100% Bonterra Energy 3/23/06 9:39 AM Page 7 t s u r T e m o c n I y g r e n E a r r e t n o B 7 Market Performance The following graph illustrates changes over the past six years in the value of $100 invested in Bonterra (of Common Shares of Bonterra Energy Corp. prior to July 1, 2001) or Trust Units, as the case may be, the TSX Composite Index and the TSX Energy Index. $1,500 $1,250 Cumulative Total Return on $100 Investment Bonterra Energy Income Trust $1,000 TSX Composite Index TSX Energy Index $750 $500 $250 0 DEC 1999 DEC 2000 DEC 2001 DEC 2002 DEC 2003 DEC 2004 DEC 2005 Dec 1999 Dec 2000 Dec 2001 Dec 2002 Dec 2003 Dec 2004 Dec 2005 Bonterra Energy Income Trust(1) TSX Composite Index TSX Energy Index $100 $100 $100 $164 $107 $146 $275 $92 $149 $481 $79 $168 $780 $98 $207 $1,242 $1,277 $111 $267 $135 $426 Note 1: Includes distributions of $8.03 per Unit since becoming a Trust. Trust Unit Trading Statistics Unit Prices (based on daily closing price) High Low Close Daily Average Trading Volume 2005 $25.97 $20.00 $23.60 26,487 2004 $26.00 $15.15 $25.10 22,918 Bonterra Energy 3/23/06 9:39 AM Page 8 t s u r T e m o c n I y g r e n E a r r e t n o B 8 P R O P E R T Y D I S C U S S I O N S 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. The Trust’s producing properties are located in the Pembina area of Alberta, the East Central area of Alberta, the Dodsland and Shaunavon areas in southwest Saskatchewan, and the southeast area of Saskatchewan. In 2005 Bonterra added quality properties in the Shaunavon area of southwest Saskatchewan and the Peck Lake area of west central Saskatchewan. Bonterra’s reserves and production growth will come primarily from internally generated exploitation and drilling programs with predictable results on existing properties. The Trust will continue to acquire exploration and development lands in the Pembina area of Alberta, and pursue other drilling opportunities in Alberta and Saskatchewan. The Trust will be reviewing and assessing strategic 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 in Canada and contains the Trust’s most significant producing property. Pembina is Bonterra’s largest core area representing 77.8% of the Trust’s total reserves. This production is predominately predictable, long life, low decline, and high quality light oil from the Cardium formation that is located at a depth of approximately 1,550 meters. Bonterra operates approximately 87 percent of its production which allows for significant operating efficiencies. The property contains approximately 360 gross (290 net) operated producing wells with an 80 percent average working interest and 145 gross (24 net) non-operated producing wells with an approximate 17 percent average working interest. This large land holding and strong infrastructure position provides a strong base to exploit a range of low risk development and exploration opportunities. Even though the Pembina area is considered a mature field it is proving to be a significant area for multi- zone oil and natural gas exploration with predictable results. The Trust has managed to increase reserves in the area through optimization and drilling as well as through key acquisitions. As a result, Bonterra has one of the longest Reserve Life Index’s and a proven record of production and reserves replacement through drilling and revisions. The Trust’s large drilling inventory has enabled it to increase production volumes. A Cardium infill drilling program was initiated on Bonterra’s non-operated properties in 2003 and has continued successfully through 2005. The Trust conducted a small operated Cardium infill program in late 2004 with results that exceeded expectations. An expanded Cardium drilling program was initiated in the fall of 2005 and will continue for a few years. The results of the expanded drilling program met expectations even though there has been a delay in getting a considerable number of wells on production because of poor weather conditions and availability of services. Bonterra has the potential to significantly increase the value of its Cardium oil from additional infill density drilling and CO2 flooding which will allow growth of its existing asset base. Most operators in the Pembina area have been reducing well spacing to 40 acres; whereas, Bonterra is generally reducing its spacing to 80 acres. There is significant uncertainty over the economic feasibility of enhanced oil recovery using CO2 to increase production from the Cardium formation; however, public information from ongoing pilots is encouraging. The Trust has a large land base that may be suitable for CO2 enhanced oil recovery and will continue to investigate its potential development. Bonterra Energy 3/23/06 9:39 AM Page 9 Bonterra is also producing from the Belly River formation. The Belly River produces high quality light sweet oil from a depth of approximately 1,100 meters. There is potential to increase production from the Belly River formations through drilling in select areas of the field. Bonterra has been able to increase natural gas production and reserves by drilling multi-zone shallow gas wells into the Edmonton and Paskapoo formations. The Trust is targeting several productive sands that range in depth from 275 to 850 meters. Bonterra has been able to significantly increase its shallow gas land base in 2005 and will capitalize on this in 2006 with an expanded drilling program. Bonterra expects to build on its previous exploration success and add to its reserve base by developing these low risk shallow gas reserves. Bonterra has been assessing production of natural gas from coals (NGC) in the Pembina area for a period of four years with encouraging initial results. Based on these results, Bonterra had hoped to proceed with a program of re-entering existing wells and drilling new wells to further assess the NGC potential. Due to regulatory delays and uncertainty by regulators, Bonterra has delayed this project until all regulatory concerns are rectified. Bonterra has extensive prospective land holdings near existing operated infrastructure in the area. NGC has the potential to add significant low risk production and reserves and the Trust will continue to t s u r T e m o c n I y g r e n E a r r e t n o B 9 pursue this opportunity. Dodsland Area, Southwest Saskatchewan The Dodsland properties produce light sweet gravity oil and solution gas from the Viking formation at a depth of approximately 700 meters. Bonterra now operates approximately 425 gross (374 net) wells with an average working interest of 88 percent. This is low rate stable production so cost control and hedge programs are important focuses of the operating strategy in this area. The Trust is continually reviewing different operating practices and improved technology that may improve the profitability of the property. Bonterra does not have an abandonment or reclamation liability for the majority of this property because under terms of an agreement Bonterra has an option to transfer uneconomic wells to the previous owner of the property. Southeast Saskatchewan The southeast properties produce slightly sour high gravity oil and solution gas primarily from the Midale formation. The Trust has an average working interest of approximately 98 percent in the area. Bonterra continues to evaluate this area to determine if further optimization programs may increase overall profitability on the properties. Some of these properties are located close to fields that have extensive CO2 flood programs; and therefore, in the future may be conducive to reserve and production increases from a CO2 flood program. Shaunavon Area, Southwest Saskatchewan Bonterra operates this major producing property which consists of 56 producing wells in the Shaunavon area of southwest Saskatchewan where the Trust’s working interest averages approximately 94 percent. The properties are located in the Whitemud and Chambery fields and produce 22 degree API crude oil from the upper Shaunavon formation located at a depth of approximately 1,500 meters. A portion of the property is being produced under waterflood with the majority of the properties still on primary production. The primary production areas are being monitored on an ongoing basis to determine if water flood programs should be initiated. The wells in the Shaunavon area generally have a very long life and stable low decline production profile after a short period of higher decline when a new well initially commences production. Bonterra Energy 3/23/06 9:39 AM Page 10 t s u r T e m o c n I y g r e n E a r r e t n o B 10 The Trust is continuing to assess its undeveloped acreage to determine if there are potential exploration or development prospects in the area. Peck Lake Area, West Central Saskatchewan The Peck Lake property is a 100 percent owned and operated shallow gas property located in west central Saskatchewan with four producing gas wells. The property was brought on production in November 2004, and is performing to expectations. The Trust will be looking to expand in this area to maximize the value of its operated infrastructure. Other Bonterra has varying interests in other producing and non-producing properties in various other areas of Alberta and Saskatchewan. Most of these properties are long term producers and may provide opportunities for increased interests in the future. M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A L Y S I S This report dated March 17, 2006 is a review of the operations, current financial position and outlook for the Trust and should be read in conjunction with the audited financial statements for the year ended December 31, 2005, together with the notes related thereto. Annual Comparisons Financial ($000, except $ per unit) Revenue - oil and gas Funds Flow from Operations (1) Per Unit Basic Per Unit Fully Diluted Net Earnings Per Unit Basic Per Unit Fully Diluted Cash Distributions per Unit Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) 2005 2004 2003 $ 75.837 44,579 2.72 2.69 33,468 2.04 2.01 2.37 56,703 110,149 21,972 57,322 2,713 5,650 $ 53,585 29,606 2.08 2.03 20,366 1.43 1.40 1.88 10,595 84,989 8,948 54,060 2,361 4,996 $ 43,449 22,228 1.66 1.64 14,016 1.05 1.04 1.55 5,691 77,837 22,552 36,983 2,384 4,403 Bonterra Energy 3/23/06 9:39 AM Page 11 t s u r T e m o c n I y g r e n E a r r e t n o B 11 Quarterly Comparisons Financial ($000, except $ per unit) Revenue - oil and gas Funds Flow from Operations (1) Per Unit Basic Per Unit Fully Diluted Net Earnings Per Unit Basic Per Unit Fully Diluted Cash Distributions Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) Financial ($000, except $ per unit) Revenue - oil and gas Funds Flow from Operations (1) Per Unit Basic Per Unit Fully Diluted Net Earnings Per Unit Basic Per Unit Fully Diluted Cash Distributions Capital Expenditures and Acquisitions Total Assets Working Capital Deficiency Unitholders’ Equity Operations Oil and Liquids (barrels per day) Natural Gas (MCF per day) 4th 3rd 2nd 1st 2005 $ 21,753 $ 20,532 $ 12,489 12,209 0.76 0.76 9,918 0.59 0.58 0.68 10,979 110,149 21,972 57,322 2,814 5,795 0.75 0.74 9,309 0.57 0.56 0.60 3,022 101,008 10,920 60,662 2,680 5,692 17,114 10,167 0.62 0.61 7,115 0.44 0.43 0.55 678 99,914 11,379 60,467 2,635 5,462 $ 16,438 9,714 0.59 0.58 7,126 0.44 0.43 0.54 42,024 102,088 11,896 61,985 2,724 5,649 4th 3rd 2nd 1st 2004 $ 14,774 $ 14,244 $ 12,536 $ 12,031 8,678 0.57 0.56 6,389 0.42 0.41 0.55 5,690 84,989 8,948 54,060 2,355 5,478 7,499 0.52 0.50 5,393 0.38 0.37 0.51 1,476 80,811 4,995 56,380 2,339 5,214 6,936 0.51 0.50 4,336 0.32 0.31 0.43 832 79,804 2,781 57,987 2,349 4,643 6,493 0.48 0.47 4,248 0.31 0.31 0.39 2,597 80,540 21,384 38,615 2,401 4,641 (1) Funds flow from operations is not a recognized measure under GAAP. Management believes that in addition to net earnings, funds flow from operations is a useful supplemental measure as it demonstrates the Trust’s ability to generate the cash necessary to make trust distributions, repay debt or fund future growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Trust’s performance. The Trust’s method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For these purposes, the Trust defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items excluding gain on sale of property. Bonterra Energy 3/23/06 9:39 AM Page 12 t s u r T e m o c n I y g r e n E a r r e t n o B 12 Officers Certification of Evaluation of Disclosure Controls The Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Trust’s disclosure controls and procedures as of December 31, 2005 and have concluded that such disclosure controls were effective to provide reasonable assurance that material information relating to the Trust or its subsidiaries is made known to them. Production The Trust’s 2005 average production of oil and natural gas liquids was 2,713 (2004 – 2,361) barrels per day and natural gas production in 2005 averaged 5,650 (2004 – 4,996) MCF per day. Oil production increased by approximately 15 percent while gas production increased by approximately 13 percent. The increases were predominantly due to the Novitas Energy Ltd. (Novitas) acquisition on January 7, 2005. The Trust’s fourth quarter production saw increases in both crude oil and natural gas production due to commencement of production from new wells drilled in 2005. The Trust’s overall annual decline rate for 2005 is approximately seven percent which the Trust was able to offset with its 2004 fall drill program. The Trust drilled six gross (4.9 net) oil wells and five gross (4.4 net) natural gas wells in November and December of 2004. Of these wells two (2 net) gas wells were dry holes and one oil well (1 net) was not tied-in until the first quarter of 2006. In August 2005 the Trust commenced with its oil infill drill program. The program which was originally planned to commence in May was delayed due to wet spring and summer weather as well as delays in obtaining a drilling rig. The Trust drilled a total of 15 (12.2 net) infill crude oil wells prior to year end. Of these wells only two were tied in and on production prior to year end. It is anticipated that the majority of the remaining wells will be tied-in and on production by the end of the first quarter of 2006. Five (2.5 net) natural gas wells were drilled by the Trust during July and one (1 net) in September. Three (1.5 net) of these wells were on production in the fourth quarter of 2005. The balance of the wells are anticipated to be on production prior to the end of the first quarter of 2006. Crude oil development drilling was also conducted on three of the Trust’s non-operated property interests with net production gains in the fourth quarter of approximately 70 barrels per day. Additional drilling is anticipated to be completed on the Trusts non- operated interests in the first quarter of 2006. Revenue Gross revenue from petroleum and natural gas sales prior to royalties was $75,837,000 (2004 - $53,585,000). The increase of $22,252,000 was due to increased production volumes from the acquisition of Novitas and substantial increases in the average price received for crude oil and natural gas. The price received for crude oil increased to $58.30 per barrel in 2005 from $47.30 per barrel in 2004 and natural gas prices increased to $8.64 per MCF in 2005 from $6.81 per MCF in 2004. The increase in Q4 gross revenues of $1,221,000 over Q3 was due primarily to increased production volumes arising from the Trust’s operated and its partner’s non-operated fall drill programs. The average price received in the fourth quarter for crude oil and natural gas liquids was $60.73 ($64.48 third quarter) per barrel and $11.16 ($8.69 third quarter) per MCF for natural gas. Although the Trust received higher net commodity prices in 2005 than in 2004, increases in the price of U.S. WTI oil prices and U.S. Nymex natural gas prices were partially offset by the rising Canadian dollar. The negative impact of the rising Canadian dollar on 2005 funds flow from operations was approximately 29 cents per unit and approximately 29 cents per unit on net earnings. Bonterra Energy 3/23/06 9:39 AM Page 13 Gross revenue has been reduced by $4,054,000 (2004 - $2,526,000) due to lower prices received as a result of price hedging. The Trust will continue to hedge future production (see Business Prospects, Risks, and Outlooks) to assist in managing its cash flow. The Trust continues to follow the policy of protecting high cost production with hedges that provide a significant level of profitability and also to provide for a reasonable amount of cash flow protection for development projects. The Trust will however maintain a policy of not hedging more than 50 percent of production to allow it to benefit from any price movements in either crude oil or natural gas. Commodity price hedges outstanding as of the date of this report are as follows: Period of Agreement Commodity Volume per day Index Price (Cdn.) January 1, 2006 to March 31, 2006 Crude Oil 500 barrels April 1, 2006 to June 30, 2006 Crude Oil 500 barrels July 1, 2006 to September 30, 2006 Crude Oil 500 barrels WTI WTI WTI $55.12 per barrel $65.07 per barrel Floor of $65.00 and ceiling of $77.52 per barrel October 1, 2006 to December 31, 2006 Crude Oil 500 barrels WTI Floor of $70.00 per barrel and ceiling of May 1, 2005 to March 31, 2006 Natural Gas 2,000 GJ’s AECO Floor of $6.75 per GJ (May 1, 2005 to $80.10 per barrel t s u r T e m o c n I y g r e n E a r r e t n o B 13 November 1, 2005 to March 31, 2006 Natural Gas 1,500 GJ’s April 1, 2006 to October 31, 2006 Natural Gas 2,000 GJ’s AECO AECO Royalties October 31, 2005) and ceiling of $12.25 per GJ (November 1, 2005 to March 31, 2006) Floor of $6.00 and ceiling of $9.45 per GJ Floor of $8.55 and Ceiling of $14.00 per GJ Royalties paid by the Trust consist primarily of Crown royalties paid to the Provinces of Alberta and Saskatchewan. During 2005 the Trust paid $6,986,000 (2004 - $4,379,000) in Crown royalties and $2,009,000 (2004 - $1,240,000) in freehold royalties, gross overriding royalties and net carried interests. The majority of the Trust’s wells are low productivity wells and therefore have low Crown royalty rates. The Trust’s average Crown royalty rate is approximately nine percent (2004 – eight percent) and approximately three percent (2004 – two percent) for other royalties before hedging adjustments. The acquisition of Novitas resulted in a slight increase in the 2005 royalty rates. The Trust is eligible for Alberta Crown Royalty rebates for Alberta production from all wells that it drilled on Crown lands and from a small amount of purchased wells. Gain on Sale of Property On April 8, 2005, a former subsidiary of Novitas, Pine Cliff Energy Ltd.’s (Pine Cliff) (with common directors and management with Bonterra) rights offering closed with over 97 percent of former Novitas shareholders exercising their rights to acquire common shares in Pine Cliff for $0.15 per common share. As part of the rights offering, the Trust agreed to sell to Pine Cliff effective January 1, 2005 (closing April 8, 2005) approximately 18 BOE per day of production and some exploration lands formerly held by Novitas for proceeds of approximately $1,000,000. As a result of this sale the Trust reported a gain on sale of property of $225,000. The balance of the gain of $38,000 relates to a disposition of an interest in another non-core area property. Bonterra Energy 3/23/06 9:39 AM Page 14 t s u r T e m o c n I y g r e n E a r r e t n o B 14 Production Costs Production costs totalled $20,203,000 in 2005 compared to $16,438,000 in 2004. On a barrel of oil equivalent (BOE) basis 2005 operating costs were $15.14 compared to $14.06 for 2004. BOE’s are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and as such may be misleading if used in isolation. The increases in operating costs were primarily due to four factors. Firstly the acquisition of Novitas resulted in approximately $2,000,000 of additional costs. Secondly, during 2005 the Trust settled a 2000 to 2003 natural gas processing fee adjustment with the operator of several of the Trust’s natural gas processing plants. This adjustment resulted in approximately $600,000 of additional processing fees being charged to operations in 2005. Thirdly, a pipeline spill in March which resulted in an additional $100,000 (net of insurance claim) of operating costs. Finally costs of goods and services in the petroleum sector increased significantly over the past 12 months. Operating costs were $5,541,000 in the fourth quarter of 2005 compared to $5,038,000 in the third quarter. The increase was due to a $150,000 (net to the Trust) property tax adjustment in relation to a non-operated property, additional costs related to winter road maintenance and significant increases of up to 20 percent in service rig and other operating costs. As discussed above, the Trust’s production comes primarily from low productivity wells. These wells generally result in higher operating costs on a per unit-of-production basis as costs such as municipal taxes, surface lease, power and personnel costs are not variable with production volumes. The Trust is continually examining means of reducing operating costs. Operating costs in the $13 to $14 per BOE range are expected for 2006. The high operating costs for the Trust are substantially offset by low royalty rates of approximately 11 percent, which is much lower than industry average for conventional production and results in high cash net backs on a combined basis despite higher than average operating costs. General and Administrative Expense General and administrative expenses were $2,420,000 in 2005 compared to $1,287,000 in 2004. On a BOE basis, general and administrative expenses in 2005 averaged $1.81 compared to $1.10 per BOE in 2004. The Trust is managed internally. In addition, the Trust provides administrative services to Comaplex Minerals Corp. (Comaplex) and Pine Cliff, companies that share common directors and management. The Trust received a management fee from Comaplex of $240,000 (2004 - $240,000) and $132,000 from Pine Cliff for management services and office administration. The fees for the services are representative of the fair value for the services rendered. Fees for these services are deducted from the Trusts general and administrative expenses. During 2004 (prior to the takeover), the Trust received a management fee from Novitas for management services of $20,000 per month plus five percent of before tax income. In addition, the Trust accrued $500,000 at the 2004 year end representing compensation for additional engineering, accounting and management services rendered to Novitas during 2004 and prior years. These fees resulted in a reduction of over $750,000 in the Trusts 2004 administration costs. The Trust has an employee incentive plan equal to three percent of net earnings before taxes. In 2005 net earnings before taxes increased to $33,548,000 from $21,538,000 in 2004 resulting in an additional $370,000 of employee compensation expense. Bonterra Energy 3/23/06 9:39 AM Page 15 t s u r T e m o c n I y g r e n E a r r e t n o B 15 The fourth quarter general and administrative expenses were $177,000 lower than the third quarter. The decrease was primarily due to incurring several one time costs in the third quarter for third party consulting fees. In addition, historically the third quarter is the highest quarter for general and administrative costs as several reoccurring costs for general office expense items are incurred in the third quarter. Interest Expense Interest expense for the 2005 fiscal year for the Trust was $575,000 (2004 - $493,000). The increase was due to increased loan balances resulting from the Novitas acquisition. Interest rate charges during the year on the outstanding debt averaged approximately 4.7 (2004 – 4.8) percent. The Trust maintained an average outstanding debt balance of approximately $12,250,000 (2004 - $10,200,000). Total debt as of December 31, 2005 represents less than six months of 2005 annual funds flow. The Trust believes that maintaining debt at less than one year’s funds flow (calculated quarterly based on annualized quarterly results) is an appropriate level to allow it to take advantage in the future of either acquisition opportunities or to provide flexibility to develop its infill oil, shallow gas and natural gas from coals potential without requiring the issuance of trust units. The Trust’s current bank agreements (each of Bonterra Energy Corp, Comstate Resources Ltd. and Novitas have their own) provide for a combined $36,900,000 of available credit facility. The interest rate charged on all non Banker Acceptances (BA’s) facility borrowings is bank prime. The Trust’s banking arrangements allow it to use BA’s as part of its loan facility. Interest charges on BA’s are generally one third percent lower than that charged on the general loan account. Unit Based Compensation The Trust is required to record a compensation expense over the vesting period of its unit options based on the fair value of the unit options granted to employees, directors and consultants. During the year 407,000 unit options were granted. The fair value of options granted has been estimated using the Black-Scholes option pricing model, assuming a weighted risk free interest rate of 3.47 (2004 – 2.87) percent, expected weighted average volatility of 31 (2004 – 30) percent, expected weighted average life of 2.5 (2004 – 3) years and an annual dividend rate based on the distributions paid to the Unitholders during the year. The result of applying the above, a total unit based compensation of $1,023,000, based on currently issued and outstanding options, is required to be recorded over the years 2005 to 2007. Of the above amount, unit based compensation of $498,000 was recorded in 2005. Depletion, Depreciation, Accretion and Dry Hole Costs The Trust follows the successful efforts method of accounting for petroleum and natural gas exploration and development costs. Under this method, the costs associated with dry holes are charged to operations. For intangible capital costs that result in the addition of reserves, the Trust depletes its oil and natural gas intangible assets using the unit-of-production basis by field. The Trust believes that the successful efforts method of accounting provides a more accurate cost of the producing properties than the alternative measure of full cost accounting. For tangible assets such as well equipment, a life span of ten years is estimated and the related tangible costs are depreciated at one tenth of original cost per year. The use of a ten year life span instead of calculating depreciation over the life of reserves was determined to be more representative of actual costs of tangible property. Given the Trust’s long production life, wells generally require replacement of tangible assets more than once during their life time. Most of the Trust’s wells have been producing since the 1960’s and are expected to continue to produce for at least another twenty years. Bonterra Energy 3/23/06 9:39 AM Page 16 t s u r T e m o c n I y g r e n E a r r e t n o B 16 Provisions are made for asset retirement obligations through the recognition of the fair value of obligations associated with the retirement of tangible long-life assets being recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset. At December 31, 2005, the estimated total undiscounted amount required to settle the asset retirement obligations was $39,921,000 (2004 - $28,360,000). Of the $11,561,000 increase, $4.2 million is due to the Novitas acquisition and approximately $1 million due to the buyout of an operating contract with an operator in the Dodsland area of Saskatchewan whereby the operator no longer is required to pay for the abandonment of wells. The remaining increase is due to additional wells (see production) and increased cost estimates for abandonment. These obligations will be settled based on the useful lives of the underlying assets, which extend up to 40 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of five percent. The discount rate is reviewed annually and adjusted if considered necessary. A change in the rate would have a significant impact on the amount recorded for asset retirement obligations. Based on the current provision, a one percent increase in the risk adjusted rate would decrease the asset retirement obligation by $1,990,000. While a one percent decrease in the risk adjusted rate would increase the asset retirement obligation by $2,600,000. The above calculation requires an estimation of the amount of the Trust’s petroleum reserves by field. This figure is calculated annually by an independent engineering firm and any adjustments are used to recalculate depletion and asset retirement obligations. This calculation is to a large extent subjective. Reserve adjustments are affected by economic assumptions as well as estimates of petroleum products in place and methods of recovering those reserves. To the extent reserves are increased or decreased, depletion costs will vary. For the fiscal year ending December 31, 2005, the Trust expensed $10,358,000 (2004 - $8,392,000) for the above-described items. The increase of $1,966,000 over the 2004 balance is due primarily to the Novitas acquisition ($1,793,000). The entire dry hole cost of $628,000 relates to wells that were drilled in 2004 but were not determined to be dry holes until the third quarter of 2005. The delay in determining the status of the wells was due to examining whether the wells had coal-bed methane or other shallow gas productive zones which would provide sufficient production to make the wells economic. The Trust currently has an estimated reserve life for its proved developed producing reserves of 12.1 (2004 – 12.4) years calculated using the Trust’s gross reserves (prior to allowance for royalties) based on the third party engineering report dated December 31, 2005 and using fourth quarter 2005 average production rates. Based on total proved reserves the Trust has a 13.8 (2004 – 13.3) year reserve life and if proved and probable are used the reserve life increases to 17.3 (2004 – 16.5) years. These figures are some of the longest (excluding oil sands) reserve life indexes in the Trust sector. Income Taxes Taxable income earned within the Trust is required to be allocated to its Unitholders and as such the Trust will not incur any current taxes. However, the Trust operates its oil and gas interests through its 100 percent owned subsidiaries Bonterra Energy Corp. Bonterra Energy 3/23/06 9:39 AM Page 17 t s u r T e m o c n I y g r e n E a r r e t n o B 17 (Bonterra Corp.), Comstate Resources Ltd. (Comstate Ltd.) and Novitas. All operating companies pay the majority of their income to the Trust through interest and royalty payments which are deductible for income tax purposes. For the taxation periods ending prior to 2004 Bonterra Corp. and Comstate Ltd. both paid to the Trust sufficient royalty and interest payments to eliminate all their taxable income. During 2004, due to timing of capital expenditures and other funds flow factors, Comstate Ltd. was unable to pay sufficient payments to the Trust to eliminate all of its taxable income and paid taxes of approximately $560,000. Comstate Ltd. was able to obtain a full refund of the 2004 taxes in 2005. The Province of Saskatchewan levies a resource surcharge on all oil and gas produced in the province. This surcharge applies if an individual company exceeds a minimum capital threshold or where there are related companies a combined asset threshold also applies. During 2005, Bonterra Corp. exceeded the individual company threshold in the third quarter of 2005 and is now subject to the surcharge. The Trust recorded a tax expense of $347,000 in relation to the surcharge. It is anticipated that Comstate Ltd. will exceed the individual company limit in 2006 and Novitas will be subject to the surcharge by 2007 due to the continued combined growth of the Trust’s subsidiaries. Based on the Trust’s 2005 revenues, from oil and gas production in the Province of Saskatchewan, and if all operating companies had exceeded the combined asset threshold a total tax expense of $675,000 would have been recorded. Future tax provision relates to the future taxes that exist within Bonterra Corp., Comstate Ltd. and Novitas. The liability on the balance sheet and the corresponding income recovery relates to temporary differences existing between Bonterra Corp’s., Comstate Ltd.’s and Novitas’ book value of its assets and its remaining tax pools. Provision for future tax fluctuates quarter over quarter depending on the timing of capital expenditures and funds flow levels in each respective operating company. Net Earnings The Trust’s net earnings of $33,468,000 for the year ended December 31, 2005 represents a substantial increase of $13,102,000 over the Trusts 2004 net earnings of $20,366,000. The Trust recorded net earnings per unit on a fully diluted bases in 2005 of $2.04 verses $1.40 in the 2004 year. This represents a return on Unitholders’ equity of approximately 58.4 (2004 - 37.7) percent based on year end Unitholders’ equity. The Trust has an average cost for its oil and gas assets of $5.08 per BOE of proved reserves resulting in a low depletion provision. This low cost combined with moderate administration and interest expenses all contribute towards the significant net earnings. Funds Flow from Operations Funds flow from operations for the year ending December 31, 2005 was $44,579,000 compared to $29,606,000 for the year ended December 31, 2004. Funds flow from operations is not a recognized measure under GAAP. The Trust believes that in addition to net earnings, funds flow from operations is a useful supplemental measure as it demonstrates the Trust’s ability to generate the cash necessary to make trust distributions, repay debt or fund future growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Trust’s performance. The Trust’s method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For these purposes, the Trust defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items excluding gain on sale of property. Bonterra Energy 3/23/06 9:39 AM Page 18 t s u r T e m o c n I y g r e n E a r r e t n o B 18 The increase was primarily due to higher commodity prices and higher production volumes. As with all oil and gas producers the Trust’s funds flow is highly dependent on commodity prices. International events and control of crude oil production by OPEC are likely factors that will result in 2006 commodity prices being high and having a positive impact on funds flow. The following reconciliation compares funds flow to the Trust’s net earnings as calculated according to Canadian generally accepted accounting principles: Three Months Twelve Months For the periods ended December 31 2005 2004 2005 2004 Net earnings for the period $ 9,918,000 $ 6,389,000 $33,468,000 $20,366,000 Unit based compensation Dry hole costs Depletion, depreciation and accretion Future income taxes 145,000 11,000 2,395,000 20,000 41,000 480,000 1,846,000 (78,000) 498,000 628,000 9,730,000 255,000 236,000 480,000 7,912,000 612,000 Funds flow from operations $12,489,000 $ 8,678,000 $44,579,000 $29,606,000 Cash Netback The following table illustrates the Trust’s cash netback: $ per Barrel of Oil Equivalent (BOE) Production volumes (BOE) Gross production revenue Royalties Field operating Field netback General and administrative Interest and taxes Cash netback 2005 1,334,075 56.85 (6.74) (15.14) 34.97 (1.81) (0.30) 32.86 $ $ 2004 1,168,993 45.83 (4.79) (14.06) 26.98 (1.10) (0.90) 24.98 $ $ Due to the Trust’s low royalty rate, the average increase of 24 percent in the gross production revenue resulted in a 31.5 percent increase in the Trust’s cash netback. Liquidity and Capital Resources During 2005 the Trust participated in drilling 48 gross (18.5 net) wells at a total cost of $15,810,000. Of these wells, 42 gross (15 net) were oil wells and 6 gross (3.5 net) were natural gas wells. The Trust’s operated 2005 drill program consisted of 15 gross (12.2 net) Cardium oil wells and 6 gross (3.5 net) natural gas wells. Only two (2 net) oil wells drilled by the Trust were tied in and on production prior to year end. The majority of the remaining wells will be tied-in and on production by the end of the first quarter of 2006. Approximately one-third of the non-operated crude oil wells were on production by year end. Three (1.5 net) of the natural gas wells were on production in the fourth quarter of 2005. The balance of the wells are anticipated to be on production prior to the end of the first quarter of 2006. The Trust currently has plans to drill a combined total of 50 gross (37.5 net) infill Cardium, shallow gas and natural gas from coal wells Bonterra Energy 3/23/06 9:39 AM Page 19 t s u r T e m o c n I y g r e n E a r r e t n o B 19 in 2006. Total capital costs of approximately $21,600,000 for the planned development programs are anticipated to be funded out of current funds flow, existing lines of credit and funds from the exercising of employee unit options. The Trust is continuing with its efforts to acquire producing and non producing properties through either property or corporate acquisitions. The Trust has no contractual obligations that last more than one year other than its office lease agreement which is as follows: Contract Obligations Total Less than 1 year 1 – 3 years 4 – 5 years After 5 years Office lease $2,272,000 $248,000 $857,000 $619,000 $548,000 At December 31, 2005 the Trust had bank debt of $20,177,000 (2004 – $3,861,000). The Trust through its operating subsidiaries has bank revolving credit facilities totalling $36,900,000 at December 31, 2005 (December 31, 2004 - $32,000,000). The facilities carry an interest rate of Canadian chartered bank prime. The terms of the credit facilities provide that the loans are due on demand and are subject to annual review. The credit facilities have no fixed payment requirements. The amount available for borrowing under the credit facilities is reduced by outstanding letters of credit of $340,000 at December 31, 2005. Collateral for the loans consists of a demand debenture providing a first floating charge over all of the Trust’s assets, and a general security agreement. The Trust is authorized to issue an unlimited number of trust units without nominal or par value. The following table outlines changes in the Trust’s unit structure over the past two years. Issued Trust Units 2005 2004 Number Amount Number Amount Balance, beginning of year 14,943,405 $75,486,000 13,521,405 $ 51,763,000 Transfer of contributed surplus to Unit capital Issued pursuant to public offering Unit issue costs for public offering Units issued on acquisition of Novitas Unit issue costs on acquisition of Novitas Issued pursuant to Trust unit option plan Balance, end of year – – – 1,335,753 – 256,000 16,535,158 169,000 – – 5,681,000 (259,000) 2,823,000 – 1,100,000 – – 159,000 21,450,000 (1,178,000) – 322,000 3,292,000 $83,900,000 14,943,405 $ 75,486,000 The Trust issued 1,335,753 units at a value of $25 per unit plus paid $769,000 in cash for all of the issued and outstanding common shares of Novitas. For accounting purposes the transaction was recorded at the cost of the Novitas’ assets and liabilities due to Novitas being considered a related party to the Trust. The Trust provides an option plan for its directors, officers, employees and consultants. Under the plan, the Trust may grant options for up to 1,635,000 (2004 – 1,323,450) trust units. The exercise price of each option granted equals the market price of the trust unit on the date of grant and the option’s maximum term is five years. Bonterra Energy 3/23/06 9:39 AM Page 20 t s u r T e m o c n I y g r e n E a r r e t n o B 20 A summary of the status of the Trust’s unit option plan as of December 31, 2005 and 2004, and changes during the years ending on those dates is presented below: Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 2005 Options Weighted-Average 2004 Options Weighted-Average Exercise Price Exercise Price 565,000 407,000 (256,000) (70,000) 646,000 214,000 $ 11.56 23.32 11.03 16.35 $ 18.67 $ 10.89 937,000 10,000 (322,000) (60,000) 565,000 152,000 $ 10.96 15.60 10.22 10.00 $ 11.56 $ 11.52 The following table summarizes information about unit options outstanding at December 31, 2005: Range of Exercise Prices $10.00 $15.20-$15.60 $22.45-$23.35 $10.00-$23.35 Number Outstanding At 12/31/05 177,500 79,500 389,000 646,000 Options Outstanding Weighted-Average Remaining Contractual Life Options Exercisable Number Weighted-Average Exercise Price Exercisable Weighted-Average At 12/31/05 Exercise Price 1.1 years 1.3 years 3.3 years 2.2 years $10.00 15.24 23.32 $18.67 177,500 36,500 – 214,000 $10.00 15.22 – $10.89 Business Prospects, Risks, and Outlooks The resource industry operates with a great deal of risk. The most significant risks may come from oil and natural gas price swings, the uncertainty of finding new reserves from drilling programs or acquisitions, competition within the industry, and increasing environmental controls and regulations. The prices received for crude oil are established by world market forces and for natural gas by forces within North America. Fluctuations in pricing can have extremely positive or negative effects on the Trust’s funds flow or in the value of its producing and non-producing oil and natural gas properties. The Trust presently attempts to minimize these risks by pursuing both oil and natural gas activities and operates its oil and natural gas interests in areas which have long life reserves, where it has the technical expertise to enhance production, control operating costs and to increase margins of profit. The Trust also maintains an active hedging program. Currently the Trust has forward sales agreements in place for approximately 18 percent on a BOE basis of its estimated 2006 production. The Trust uses a combination of fixed price swaps as well as no cost floor and collars to protect against commodity price declines. Sensitivity Analysis Sensitivity analysis, as estimated for 2006: U.S. $1.00 per barrel Canadian $0.10 per MCF Change of Canadian $0.01/U.S. $ exchange rate Additional Information Cash Flow $ 1,037,000 $ 238,000 $ 644,000 Cash Flow Per Unit $0.063 $0.014 $0.039 Additional information relating to the Trust may be found on SEDAR.COM as well as on the Trust’s web sight at www.bonterraenergy.com. Bonterra Energy 3/23/06 9:39 AM Page 21 M A N A G E M E N T ’ S R E S P O N S I B I L I T Y F O R F I N A N C I A L S T A T E M E N T S 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. t s u r T e m o c n I y g r e n E a r r e t n o B 21 George F. Fink President and CEO Garth E. Schultz Vice President, Finance and CFO A U D I T O R S ’ R E P O R T To the Unitholders of Bonterra Energy Income Trust: We have audited the consolidated balance sheets of Bonterra Energy Income Trust as at December 31, 2005 and 2004 and the consolidated statements of Unitholders’ equity, operations and accumulated income, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as, evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Trust as at December 31, 2005 and 2004 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles. Calgary, Alberta March 17, 2006 Chartered Accountants Bonterra Energy 3/23/06 9:39 AM Page 22 t s u r T e m o c n I y g r e n E a r r e t n o B 22 C O N S O L I D A T E D B A L A N C E S H E E T S As at December 31 Assets Current Accounts receivable Crude oil inventory Parts inventory Prepaid expenses Investment in related party (Note 3) Abandonment deposit (Note 4) Property and Equipment (Note 5) Petroleum and natural gas properties and related equipment Accumulated depletion and depreciation Liabilities Current Distribution payable Accounts payable and accrued liabilities Debt (Note 6) Future income tax liability (Note 7) Asset retirement obligations (Note 8) Unitholders’ Equity Unit capital (Note 9) Contributed surplus Accumulated earnings Accumulated cash distributions On behalf of the Board: 2005 2004 $ 11,020,000 $ 7,104,000 836,000 221,000 781,000 461,000 13,319,000 – 139,798,000 (42,968,000) 96,830,000 569,000 391,000 1,040,000 461,000 9,565,000 1,522,000 102,679,000 (28,777,000) 73,902,000 $ 110,149,000 $ 84,989,000 $ 3,638,000 $ 2,690,000 11,476,000 20,177,000 35,291,000 4,341,000 13,195,000 52,827,000 83,900,000 636,000 85,156,000 (112,370,000) 57,322,000 11,962,000 3,861,000 18,513,000 997,000 11,419,000 30,929,000 75,486,000 307,000 51,688,000 (73,421,000) 54,060,000 $ 110,149,000 $ 84,989,000 Director Director Bonterra Energy 3/23/06 9:39 AM Page 23 C O N S O L I D A T E D S T A T E M E N T S O F U N I T H O L D E R S ’ E Q U I T Y For the Years Ended December 31 2005 2004 Unitholders equity, beginning of year Net earnings for the year Net capital contributions (Note 9) Units issued on acquisition of Novitas Energy Ltd. (Note 9) Unit issue costs on acquisition of Novitas Energy Ltd. (Note 9) Unit option adjustment for options expensed Cash distributions Unitholders’ Equity, End of Year $ 54,060,000 $ 36,983,000 33,468,000 2,823,000 5,681,000 (259,000) 498,000 (38,949,000) 20,366,000 23,563,000 – – 236,000 (27,088,000) $ 57,322,000 $ 54,060,000 C O N S O L I D A T E D S T A T E M E N T S O F O P E R A T I O N S A N D A C C U M U L A T E D I N C O M E For the Years Ended December 31 2005 2004 t s u r T e m o c n I y g r e n E a r r e t n o B 23 Revenue Oil and gas sales Royalties Alberta royalty tax credit Gain on sale of property (Note 5) Interest and other Expenses Production costs General and administrative Interest on debt Unit based compensation Dry hole costs Depletion, depreciation and accretion Earnings Before Income Taxes Income taxes (recovery) (Note 7) Current Future Net Earnings for the Year Accumulated earnings at beginning of year Accumulated Earnings at End of Year Net Earnings Per Unit - Basic (Note 1) Net Earnings Per Unit - Diluted (Note 1) $ 75,837,000 $ 53,585,000 (8,995,000) 464,000 263,000 33,000 (5,619,000) 305,000 – 113,000 67,602,000 48,384,000 20,203,000 2,420,000 575,000 498,000 628,000 9,730,000 34,054,000 33,548,000 (175,000) 255,000 80,000 33,468,000 51,688,000 $ 85,156,000 $ 2.04 $ 2.01 16,438,000 1,287,000 493,000 236,000 480,000 7,912,000 26,846,000 21,538,000 560,000 612,000 1,172,000 20,366,000 31,322,000 51,688,000 1.43 1.40 $ $ $ Bonterra Energy 3/23/06 9:39 AM Page 24 t s u r T e m o c n I y g r e n E a r r e t n o B 24 C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S For the Years Ended December 31 Operating Activities Net earnings for the year Items not affecting cash Gain on sale of property (Note 5) Unit based compensation Dry hole costs Depletion, depreciation and accretion Future income taxes Change in non-cash working capital Accounts receivable Crude oil inventory Parts inventory Prepaid expenses Accounts payable and accrued liabilities Asset retirement obligations settled (Note 8) Financing Activities Increase (decrease) in debt Proceeds on issuance of units pursuant to public offering Unit issue costs Unit option proceeds Unit issue costs on acquisition of Novitas Energy Ltd. Unit distributions Investing Activities Property and equipment expenditures Proceeds on sale of property (Note 5) Abandonment deposit (Note 4) Cash portion of Novitas Energy Ltd. acquisition (Note 2) Change in non-cash working capital Accounts receivable Accounts payable and accrued liabilities Net cash inflow Cash, beginning of year Cash, End of Year Cash Interest Paid Cash Taxes Paid 2005 2004 $ 33,468,000 $ 20,366,000 (263,000) 498,000 628,000 9,730,000 255,000 44,316,000 (2,814,000) (134,000) 170,000 306,000 (2,584,000) (275,000) (5,331,000) 38,985,000 11,717,000 – – 2,823,000 (259,000) (38,001,000) (23,720,000) (16,669,000) 1,097,000 1,522,000 (769,000) (14,819,000) (534,000) 88,000 (446,000) (15,540,000) – – – 575,000 894,000 $ $ $ – 236,000 480,000 7,912,000 612,000 29,606,000 (1,750,000) 80,000 (31,000) (324,000) 2,236,000 (348,000) (137,000) 29,469,000 (17,969,000) 21,450,000 (1,178,000) 3,292,000 – (26,021,000) (20,426,000) (10,595,000) – (1,522,000) – (12,117,000) (849,000) 3,923,000 3,074,000 (9,391,000) – – – 493,000 17,000 $ $ $ Bonterra Energy 3/23/06 9:39 AM Page 25 N O T E S T O T H E C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S For the Years Ended December 31, 2005 and 2004 1. SIGNIFICANT ACCOUNTING POLICIES Consolidation These consolidated financial statements include the accounts of Bonterra Energy Income Trust (the “Trust”) and its wholly owned subsidiaries Bonterra Energy Corp. (Bonterra), Comstate Resources Ltd. (Comstate) and effective January 7, 2005, Novitas Energy Ltd. (Novitas) Measurement Uncertainty The amounts recorded for depletion and depreciation of petroleum and natural gas property and equipment and for asset retirement obligations are based on estimates of petroleum and natural gas reserves and future costs. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material. Inventories Inventories consist of crude oil as well as materials and supplies which include tubing, rods, motors, pump jacks, bases and miscellaneous parts used in the maintenance of the Trust’s tangible equipment. Both crude oil and materials and supplies are valued at the lower of cost or net realizable value. Inventory cost for crude oil is determined based on combined average per barrel operating costs, royalties and depletion and depreciation for the year and net realizable value is determined based on sales price in t s u r T e m o c n I y g r e n E a r r e t n o B 25 the month preceding year end. Investments Investments are carried at the lower of cost and market value. Property and Equipment Petroleum and Natural Gas Properties and Related Equipment The Trust follows the successful efforts method of accounting for petroleum and natural gas properties and related equipment. Costs of acquiring unproved properties are capitalized. These costs are assessed at least annually, and when circumstances change, for impairment. When property is found to contain proved reserves as determined by the Trusts engineers, the related net book value is depleted on the unit-of-production basis, calculated by field. The costs of dry holes and abandoned properties are charged to operations. Geological costs, lease rentals and carrying costs are charged to income as incurred. Costs of drilling exploratory and development wells that result in additions to proved reserves are capitalized and depleted on the unit-of-production basis. Tangible equipment is depreciated on a straight-line basis over ten years. Furniture, Fixtures and Office Equipment These assets are recorded at cost and depreciated over a three to ten year period representing their estimated useful lives. Income Taxes Income taxes are calculated using the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributable to differences between the amounts reported for assets and liabilities by the Trusts subsidiary companies in the consolidated financial statements of the Trust and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future tax liabilities and assets is recognized in income in the period in which the change occurs. Bonterra Energy 3/23/06 9:39 AM Page 26 t s u r T e m o c n I y g r e n E a r r e t n o B 26 The Trust is a taxable entity under the Income Tax Act (Canada) and is taxable only on income that is not distributed or distributable to the Unitholders. As the Trust allocates all of its taxable income to the Unitholders in accordance with the Trust Indenture, and meets the requirements of the Income Tax Act (Canada) applicable to the Trust, no provision for income tax expense has been made in the Trust. However, the Trust’s subsidiaries are subject to taxation on income which is not transferred to the Trust. In the Trust structure, payments are made between the Trusts operating subsidiaries and the Trust which result in the transferring of taxable income from the operating subsidiaries to individual Unitholders. These payments may reduce future income tax liabilities previously recorded by the operating companies which would be recognized as a recovery of income tax in the period incurred. Asset Retirement Obligations The fair value of obligations associated with the retirement of long-life assets are recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset. Trust-Unit-Based Compensation The Trust has a unit-based compensation plan, which is described in Note 9. The Trust records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. These amounts are recorded as contributed surplus. Any consideration paid by employees, directors or consultants on the exercise of these options is recorded as unit capital together with the related contributed surplus associated with the exercised options. Revenue Recognition Revenues associated with sales of petroleum and natural gas are recorded when title passes to the customer. Hedging Derivative financial instruments are utilized to reduce commodity price risk on the Trust’s product sales. The Trust does not enter into financial instruments for trading or speculative purposes. The Trust’s policy is to formally designate each derivative financial instrument as a hedge of a specifically identified product sale. The Trust assesses the derivative financial instruments for effectiveness as hedges, both at inception and over the term of the instrument. The production volume in the derivative financial instruments all match the production being hedged. Commodity price swap agreements are used as part of the Trust’s program to manage its product pricing. The commodity price swap agreements involve the periodic exchange of payments and are recorded as adjustments of net revenue. For the twelve months ended December 31, 2005 the Trust recorded a reduction to net revenue of $4,054,000 (2004 - $2,526,000). Joint Interest Operations Significant portions of the Trust’s oil and gas operations are conducted with other parties and accordingly the financial statements reflect only the Trust’s proportionate interest in such activities. Net Earnings Per Unit Basic earnings per unit are computed by dividing earnings by the weighted average number of units outstanding during the year. Diluted per unit amounts reflect the potential dilution that could occur if options or warrants to purchase trust units were exercised. The treasury stock method is used to determine the dilutive effect of trust unit options and warrants, whereby proceeds from the exercise of trust unit options or other dilutive instruments are assumed to be used to purchase trust units at the average market price during the period. Bonterra Energy 3/23/06 9:39 AM Page 27 t s u r T e m o c n I y g r e n E a r r e t n o B 27 The number of trust units used to calculate diluted net earnings per unit for the year ended December 31, 2005 of 16,594,260 (2004 – 14,557,489) included the weighted average number of units outstanding of 16,388,621 (2004 – 14,217,550) plus 205,639 (2004 – 339,939) units related to the dilutive effect of unit options. 2. ACQUISITION OF NOVITAS On January 7, 2005 the Trust acquired Novitas. The acquisition was accounted for at Novitas’ carrying value due to the related status of Novitas to the Trust. The carried values where as follows: Accounts receivable Crude oil inventory Prepaid expenses Property and equipment Accumulated depletion and depreciation Accounts payable and accrued liabilities Debt Future income tax liability Asset retirement obligations $ 568,000 122,000 47,000 23,130,000 (6,522,000) (2,010,000) (4,598,000) (3,089,000) (1,198,000) $ 6,450,000 The acquisition cost was $769,000 cash and the issuance of 1,335,753 trust units. 3. INVESTMENT IN RELATED PARTY The investment consists of 689,682 (December 31, 2004 – 689,682) common shares in Comaplex Minerals Corp (Comaplex), a company with common directors and management. The investment is recorded at cost. The fair market value as determined by using the trading price of the stock at December 31, 2005 was $2,448,000 (December 31, 2004 - $2,414,000). The common shares trade on the Toronto Stock Exchange under the symbol CMF. The investment represents less than a two percent ownership in the outstanding shares of Comaplex. 4. ABANDONMENT DEPOSIT As required by Province of Alberta Regulations the Trust provided a cash deposit with the Alberta Energy and Utilities Board for the future abandonment of specific wells. The deposit was refundable based on several conditions including abandonment or reactivation of inactive wells as well as meeting certain financial conditions. During the year the Trust was refunded the entire deposit. The deposit bore interest at Canadian chartered bank prime less approximately 2 percent. 5. PROPERTY AND EQUIPMENT 2005 2004 Accumulated Depletion and Depreciation Cost Accumulated Depletion and Depreciation Cost Undeveloped land $ 334,000 $ - $ 308,000 $ - Petroleum and natural gas properites and related equipment 138,713,000 42,622,000 101,661,000 28,523,000 Furniture, equipment and other 751,000 346,000 710,000 254,000 $139,798,000 $ 42,968,000 102,679,000 $ 28,777,000 Bonterra Energy 3/23/06 9:39 AM Page 28 t s u r T e m o c n I y g r e n E a r r e t n o B 28 On April 8, 2005, a former subsidiary of Novitas, Pine Cliff Energy Ltd.’s (Pine Cliff) (with common directors and management with the Trust) rights offering closed with over 97 percent of former Novitas shareholders exercising their rights to acquire common shares in Pine Cliff for $0.15 per common share. As part of the rights offering, the Trust agreed to sell to Pine Cliff effective January 1, 2005 (closing April 8, 2005) approximately 18 barrels per day of oil equivalent of production and some exploration lands formally held by Novitas for proceeds of approximately $1,000,000. As a result of this sale the Trust reported a gain on sale of property of $225,000. The Trust also disposed of minor non-core area properties for proceeds of $97,000 for a gain of $38,000. 6. DEBT The Trust has a bank revolving credit facility of $36,900,000 at December 31, 2005 (2004 - $32,000,000). 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 outstanding letters of credit. Letters of credit totalling $340,000 were issued at December 31, 2005. Collateral for the loan consists of a demand debenture providing a first floating charge over all of the Trust’s assets, and a general security agreement. The credit facility carries an interest rate of Canadian chartered bank prime. The Trust has classified borrowing under its bank facilities as a current liability as required by guidance under the CICA’s Emerging Issues Committee Abstract 122. It has been management’s experience that these types of loans which are required to be classified as a current liability are seldom called by principal bankers as long as all the terms and conditions of the loan are complied with. Cash interest paid during the year ended December 31, 2005 for this loan was $575,000 (2004 - $455,000). 7. INCOME TAXES The Trust has recorded a future income tax liability related to assets and liabilities and related tax amounts held through its 100 percent owned operating subsidiaries. The liability relates to the following temporary differences in those subsidiaries: Temporary differences related to assets and liabilities of the subsidiary companies Finance costs in corporate subsidiaries Corporate tax losses carried forward in the subsidiary companies 2005 2004 $ $ 5,919,000 (12,000) (1,566,000) 4,341,000 $ 1,636,000 (33,000) (606,000) $ 997,000 Income tax expense varies from the amounts that would be computed by applying Canadian federal and provincial income tax rates as follows: Earnings before income taxes Combined federal and provincial income tax rates Income tax provision calculated using statutory tax rates Increase (decrease) in income taxes resulting from: Saskatchewan resource surcharge Unit based compensation Non-deductible crown royalties Resource allowance Trust income allocated to Unitholders Adjustment on acquisition of Novitas Others $ 2005 33,548,000 38.08% 12,775,000 347,000 190,000 1,793,000 (3,283,000) (12,763,000) 1,055,000 (34,000) 80,000 $ 2004 21,538,000 39.00% 8,400,000 – 92,000 1,317,000 (2,399,000) (6,181,000) – (57,000) 1,172,000 $ $ Bonterra Energy 3/23/06 9:39 AM Page 29 The Trust’s subsidiaries have the following tax pools, which may be used to reduce taxable income in future years, limited to the applicable rates of utilization: Undepreciated capital costs Canadian oil and gas property expenditures Canadian development expenditures Canadian exploration expenditures Income tax losses carried forward (1) Finance costs Rate of Utilization % 20-100 10 30 100 100 20 Amount $ 8,199,000 1,382,000 13,981,000 93,000 4,497,000 34,000 $ 28,186,000 (1) Income tax losses carried forward expire in 2014 ($635,000) and 2015 ($3,862,000). The Trust has the following tax pools, which may be used in reducing future taxable income allocated to its Unitholders: t s u r T e m o c n I y g r e n E a r r e t n o B 29 Canadian oil and gas property expenditures Finance costs Eligible capital expenditures 8. ASSET RETIREMENT OBLIGATIONS Rate of Utilization % 10 20 7 Amount $ 17,886,000 913,000 180,000 $ 18,979,000 At December 31, 2005, the estimated total undiscounted amount required to settle the asset retirement obligations was $39,921,000 (2004 - $28,360,000). Costs for asset retirement have been calculated assuming a 2.5 percent inflation rate for 2006 to 2010 and 1.5 percent thereafter. These obligations will be settled based on the useful lives of the underlying assets, which extend up to 40 years into the future. This amount has been discounted using a credit-adjusted risk-free interest rate of 5 (2004 – 5) percent. Changes to asset retirement obligations were as follows: Asset retirement obligations, January 1 Adjustment to asset retirement obligation Acquisition of Novitas Liabilities settled during the year Accretion 2005 2004 $ 11,419,000 $ 11,214,000 234,000 1,197,000 (275,000) 620,000 (7,000) – (348,000) 560,000 Asset retirement obligations, December 31 $ 13,195,000 $ 11,419,000 Bonterra Energy 3/23/06 9:39 AM Page 30 t s u r T e m o c n I y g r e n E a r r e t n o B 30 9. UNIT CAPITAL Authorized The Trust is authorized to issue an unlimited number of trust units without nominal or par value. Issued Trust Units 2005 2004 Number Amount Number Amount Balance, beginning of year 14,943,405 $75,486,000 13,521,405 $ 51,763,000 Transfer of contributed surplus to Unit capital Issued pursuant to public offering Unit issue costs for public offering Units issued on acquisition of Novitas Unit issue costs on acquisition of Novitas Issued pursuant to Trust unit option plan Balance, end of year – – – 1,335,753 – 256,000 16,535,158 169,000 – – 5,681,000 (259,000) 2,823,000 – 1,100,000 – – 159,000 21,450,000 (1,178,000) – 322,000 3,292,000 $83,900,000 14,943,405 $ 75,486,000 The Trust acquired Novitas on January 7, 2005. See Note 2 for details. The Trust provides an option plan for its directors, officers, employees and consultants. Under the plan, the Trust may grant options for up to 1,635,000 (2004 – 1,323,450) trust units. The exercise price of each option granted equals the market price of the trust unit on the date of grant and the option’s maximum term is five years. A summary of the status of the Trust’s unit option plan as of December 31, 2005 and 2004, and changes during the years is presented below: Outstanding at beginning of year Options granted Options exercised Options cancelled Outstanding at end of year Options exercisable at end of year 2005 Options Weighted-Average 2004 Options Weighted-Average Exercise Price Exercise Price 565,000 407,000 (256,000) (70,000) 646,000 214,000 $ 11.56 23.32 11.03 16.35 $ 18.67 $ 10.89 937,000 10,000 (322,000) (60,000) 565,000 152,000 $ 10.96 15.60 10.22 10.00 $ 11.56 $ 11.52 The following table summarizes information about unit options outstanding at December 31, 2005: Range of Exercise Prices $10.00 $15.20-$15.60 $22.45-$23.35 $10.00-$23.35 Number Outstanding At 12/31/05 177,500 79,500 389,000 646,000 Options Outstanding Weighted-Average Remaining Contractual Life Options Exercisable Number Weighted-Average Exercise Price Exercisable Weighted-Average At 12/31/05 Exercise Price 1.1 years 1.3 years 3.3 years 2.2 years $10.00 15.24 23.32 $18.67 177,500 36,500 – 214,000 $10.00 15.22 – $10.89 Bonterra Energy 3/23/06 9:39 AM Page 31 The Trust records compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. The fair value of options granted has been estimated using the Black-Scholes option pricing model, assuming a weighted risk free interest rate of 3.5 (2004 – 2.87) percent, expected weighted average volatility of 31 (2004 – 30) percent, expected weighted average life of 2.5 (2004 – 3) years and an annual dividend rate based on the distributions paid to the Unitholders during the year. 10. RELATED PARTY TRANSACTIONS The Trust received a management fee from Comaplex of $240,000 (2004 - $240,000) for management services and office administration. This fee has been included as a recovery in general and administrative expenses. The above fee represents the fair value of the services rendered. As at December 31, 2005 the Trust had accounts receivable from Comaplex of $29,000 (December 31, 2004 - $45,000). The Trust received a management fee from Pine Cliff of $132,000 for management services and office administration. This fee has been included as a recovery in general and administrative expenses. The above fee represents the fair value of the services rendered. As at December 31, 2005 the Trust had an accounts receivable from Pine Cliff of $165. As at December 31, 2005 the Trust had an accounts payable of $16,000 to Pine Cliff in relation to outstanding post closing adjustment items for the sale of properties to Pine t s u r T e m o c n I y g r e n E a r r e t n o B 31 Cliff (see note 5). 11. FINANCIAL INSTRUMENTS Fair Values The Trust’s financial instruments included in the balance sheet are comprised of accounts receivable and current liabilities, including the revolving demand loan. The fair value of these financial instruments approximate their carrying value due to the short-term maturity of those instruments. Borrowings under bank credit facilities are for short periods with variable interest rates, thus, carrying values approximate fair value. Credit Risk Substantially all of the Trust’s accounts receivable are due from customers in the oil and gas industry and are subject to normal industry credit risks. The carrying value of accounts receivable reflects management’s assessment of associated credit risks. Interest Rate Risk The Trust’s bank debt is comprised of revolving loans at variable rates of interest, and as such, the Trust is exposed to interest rate risk. Commodity Price Risk The nature of the Trust’s operations results in exposure to fluctuations in commodity prices and exchange rates. The Trust monitors and when appropriate uses derivative financial instruments to manage its exposure to these risks. Bonterra Energy 3/29/06 1:09 PM Page 32 t s u r T e m o c n I y g r e n E a r r e t n o B 32 12. COMMITMENTS, CONTINGENCIES AND GUARANTEES The Trust entered into the following commodity hedging transactions in 2005 for a portion of its 2006 production: Period of Agreement Commodity Volume per day Index Price (Cdn.) January 1, 2006 to March 31, 2006 Crude Oil 500 barrels April 1, 2006 to June 30, 2006 Crude Oil 500 barrels July 1, 2006 to September 30, 2006 Crude Oil 500 barrels WTI WTI WTI $55.12 per barrel $65.07 per barrel Floor of $65.00 and ceiling of $77.52 per barrel May 1, 2005 to March 31, 2006 Natural Gas 2,000 GJ’s AECO Floor of $6.75 per GJ (May 1, 2005 to November 1, 2005 to March 31, 2006 Natural Gas 1,500 GJ’s April 1, 2006 to October 31, 2006 Natural Gas 2,000 GJ’s AECO AECO October 31, 2005) and ceiling of $12.25 per GJ (November 1, 2005 to March 31, 2006) Floor of $6.00 and ceiling of $9.45 per GJ Floor of $8.55 and Ceiling of $14.00 per GJ As at December 31, 2005 the fair value of the outstanding commodity hedging contracts was a net liability of $1,349,000. The Trust has no contractual obligations that last more than a year other than its office lease agreement which is as follows: Contract Obligations Total Less than 1 year 1 – 3 years 4 – 5 years After 5 years Office lease $2,272,000 $248,000 $857,000 $619,000 $548,000 13. SUBSEQUENT EVENT- COMMITMENTS The Trust entered into the following commodity hedging transactions subsequent to December 31, 2005 for a portion of its future production: Period of Agreement Commodity Volume per day Index Price (Cdn.) October 1, 2006 to December 31, 2006 Crude Oil 500 barrels WTI Floor of $70.00 per barrel and ceiling of $80.10 per barrel BNE Cover 2005 3/19/06 9:14 AM Page 3 Bonterra Energy Income Trust. (TSX symbol – BNE.UN) is an energy income trust that develops and produces oil and natural gas in the Provinces of Alberta and Saskatchewan. The Trusts business strategy is to strive to maximize unitholders value by applying long-term growth objectives. The Trust’s primary objective is to combine its oil and gas production technical strengths with planned business strategies to generate above average results and returns for our unitholders. C O N T E N T S Highlights Report to Unitholders Review of Operations Property Discussions N O T I C E O F A N N U A L G E N E R A L M E E T I N G The Annual General Meeting of Unitholders will be held on Management’s Discussion and Analysis Management’s Responsibility for Financial Statements Wednesday, May 24, 2006, in the Nakiska room at the Westin Auditors’ Report Hotel, 320 Fourth Avenue S.W., Calgary, Alberta, at 11:00 a.m. Consolidated Financial Statements (Calgary time). Notes to the Consolidated Financial Statements Trust Information 1 2 4 8 10 20 20 21 24 IBC F O R W A R D - L O O K I N G I N F O R M A T I O N Certain information set forth in this document, including management’s assessment of Bonterra Energy Income Trust’s (“the Trust” or “Bonterra”) future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Bonterra’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonterra’s actual results, performance or achievement could differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Bonterra will derive therefrom. Bonterra disclaims any intention or obligation to update or revise any forward- looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not represent fair market value of reserves. T R U S T I N F O R M A T I O N Board of Directors G.J. Drummond, Nassau, Bahamas G.F. Fink, Calgary, Alberta C.R. Jonsson, Vancouver, British Columbia F. W. Woodward, Calgary, Alberta Officers G.F. Fink – President & Chief Executive Officer R.M. Jarock – Chief Operating Officer G.E. Schultz – Vice President, Finance, Chief Financial Officer & Secretary Registrar & Transfer Agent Olympia Trust Company, Calgary, Alberta Auditors Deloitte & Touche LLP, Calgary, Alberta Solicitors Borden Ladner Gervais LLP, 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 Head Office 901, 1015 – 4th Street SW Calgary, Alberta T2R 1J4 PH 403.262.5307 FX 403.265.7488 Web Site www.bonterraenergy.com BNE Cover 2005 3/19/06 9:14 AM Page 1 901, 1015 – 4TH ST SW, CALGARY, ALBERTA T2R 1J4 2 0 0 5 A N N U A L R E P O R T