Bonavista Energy Trust
TSX : BNP.UN

Bonavista Energy Trust

March 14, 2007 16:00 ET

Bonavista Energy Trust: Announcing 2006 Year End Results

CALGARY, ALBERTA--(CCNMatthews - March 14, 2007) - Bonavista Energy Trust (TSX:BNP.UN) is pleased to report to unitholders its interim consolidated financial and operating results for the three months and year ended December 31, 2006.



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Highlights
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Three Months Years
ended ended
December 31, December 31,
2006 2005 2006 2005
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Financial
($ thousands, except per unit)

Production revenues 222,321 288,680 901,747 912,422
Funds from operations (1) 121,305 170,714 496,438 522,649
Per unit (1) (2) 1.17 1.72 4.86 5.41

Cash distributions 76,296 79,212 324,016 270,827
Per unit 0.90 0.99 3.87 3.47
Percentage of funds from
operations distributed 63% 46% 65% 52%

Net income 67,635 103,759 301,270 302,942
Per unit (2) 0.65 1.05 2.95 3.14

Total assets 2,067,931 1,934,892

Long-term debt, net of
working capital 518,448 371,709

Unitholders' equity 1,130,253 1,103,510

Capital expenditures:
Exploitation and development 58,744 90,189 280,563 235,958
Acquisitions, net (345) 997 35,790 59,094

Weighted average outstanding
equivalent trust units:
(thousands) (2)
Basic 103,533 99,133 102,156 96,520
Diluted 106,304 104,079 105,615 103,067
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Operating
(boe conversion -- 6:1 basis)

Production:
Natural gas (mmcf/day) 174 181 177 176
Oil and liquids (bbls/day) 24,114 22,338 23,068 21,421
Total oil equivalent (boe/day) 53,106 52,466 52,593 50,779

Product prices:
Natural gas ($/mcf) 7.44 11.25 7.38 8.55
Oil and liquids ($/bbl) 46.52 49.45 50.42 46.39

Operating expenses ($/boe) 8.18 7.28 7.92 6.87

General and administrative
expenses ($/boe) 0.72 0.48 0.58 0.47

Cash costs ($/boe) (3) 10.47 8.93 9.92 8.73

Operating netback ($/boe) (4) 27.12 37.01 27.85 30.06
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Drilling (gross wells) 325 342
Natural gas 220 213
Oil 86 119
Average success rate 94% 97%

Reserves:
Proved:
Natural gas (bcf) 428.2 444.2
Oil and liquids (mbbls) 63,643 62,943
Total oil equivalent (mboe) 135,006 136,977
Proved and probable:
Natural gas (bcf) 542.9 539.5
Oil and liquids (mbbls) 83,615 79,157
Total oil equivalent (mboe) 174,091 169,071
% Proved producing 62% 66%
% Proved 78% 81%
% Probable 22% 19%
Net present value of future cash flow
before income taxes ($ millions):
0% discount rate 5,449 4,702
5% discount rate 3,612 3,287
10% discount rate 2,749 2,606
Reserve life index (years):
Proved 7.3 7.4
Proved and probable 8.9 8.8

Finding and development costs -
proved and probable ($/boe):
Including changes in future development expenditures 15.29 13.13
Excluding changes in future development expenditures 13.06 12.57

Recycle ratio - proved and probable: (5)
Including changes in future development expenditures 1.8 2.3
Excluding changes in future development expenditures 2.1 2.4
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Three Months ended
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Trust Unit December 31, September 30, June 30, March 31,
Trading Statistics 2006 2006 2006 2006
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($ per unit, except volume)

High 35.50 38.34 37.80 39.86
Low 24.52 31.81 31.51 33.45
Close 28.15 32.28 35.00 37.25
Average Daily Volume 472,156 262,161 252,280 265,472
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NOTES:

(1) Management uses funds from operations to analyze operating performance
and leverage. Funds from operations as presented does not have any
standardized meaning prescribed by Canadian GAAP and therefore it may not
be comparable with the calculations of similar measures for other entities.
Funds from operations as presented is not intended to represent operating
cash flow or operating profits for the period nor should it be viewed as an
alternative to cash flow from operating activities, net income or other
measures of financial performance calculated in accordance with Canadian
GAAP. All references to funds from operations throughout this report are
based on cash flow from operating activities before changes in non-cash
working capital and asset retirement expenditures. Funds from operations
per unit is calculated based on the weighted average number of trust units
outstanding consistent with the calculation of net income per trust unit.

(2) Basic per unit calculations include exchangeable shares which are
convertible into trust units on certain terms and conditions.

(3) Cash costs equal the total of operating, general and administrative,
interest expense and cash taxes.

(4) Operating netback equals total revenue less royalties, transportation
and operating expenses, calculated on a boe basis.

(5) Recycle ratio is calculated as operating netback per boe divided by
finding and development costs per boe.


MESSAGE TO UNITHOLDERS

Bonavista Energy Trust ("Bonavista" or the "Trust") is pleased to report to its unitholders (the "Unitholders") the consolidated financial and operating results for the three months and year ended December 31, 2006. The results for the fourth quarter of 2006 represent fourteen consecutive quarters of profitability for Bonavista since commencing operations as an energy trust in July 2003. The continued successful execution of Bonavista's proven strategies in the fourth quarter of 2006 is a testament to the validity and effectiveness of an operationally and technically focused energy trust. The fourth quarter and annual results of 2006 are also highlighted by an increased selection of drilling opportunities leading to attractive finding and development costs despite the trend of increasing overall industry costs. This environment creates the opportunity for Bonavista to continue to differentiate itself by posting solid earnings in an ever-changing economic landscape. Other significant accomplishments for Bonavista in 2006 include:

- Operationally, production volumes reached a record 52,593 boe per day during 2006, which represents a 4% increase over the 50,779 boe per day reported in 2005 and a 52% increase over the 34,600 boe per day on commencement as an energy trust on July 2, 2003. Bonavista's current production rate is approximately 52,500 boe per day;

- Added 24.2 mmboe of proved and probable reserves during 2006, which replaced annual production by 1.3 times and improved the Trust's proved and probable reserve life index to 8.9 years. These reserves were added at an attractive finding and development cost, including changes in future development expenditures, of $20.85 per boe on a proved basis ($18.37 per boe excluding changes in future development expenditures) and $15.29 per boe on a proved and probable basis ($13.06 per boe excluding changes in future development expenditures). A strong proved and probable recycle ratio of 1.8:1 (1.3:1 proved) was achieved in 2006 as a result of the low level of finding and development costs. Overall in 2006, Bonavista increased proved and probable reserves by 3% to 174.1 mmboe while spending only 64% of funds from operations on exploitation, development and acquisition expenditures;

- Maintained an active capital program during 2006, having invested $280.6 million in exploitation and development activities drilling 325 wells with an overall 94% success rate, and $35.8 million in 13 synergistic acquisitions within our core regions;

- Continued to actively participate at crown land sales, investing $20.6 million in land activity during the year, further enhancing our undeveloped land position to 1.1 million net acres and our future drilling prospect inventory to more than two years;

- Generated funds from operations of $496.4 million ($4.86 per unit) in 2006 and distributed 65% of these funds to Unitholders, with the remaining funds reinvested in the business to continue growing our production base;

- Continued to record strong profitable growth in 2006 with an impressive average return on equity of 27% and a strong net income to funds from operations ratio of 60%; and

- Established a new $800 million credit facility with a syndicate of chartered banks. This facility is unsecured, covenant-based which significantly enhances Bonavista's financial flexibility to take advantage of future investment opportunities in 2007 and beyond.

On October 31, 2006, the Federal Government announced proposals pertaining to the taxation of distributions from publicly traded Canadian income trusts, royalty trusts and partnerships. The proposals include a 31.5% tax imposed on income before distributions at the trust level and taxed to the taxable Canadian investor, effectively as a dividend. If enacted, the proposals would apply to the Trust effective January 1, 2011. On December 21, 2006, the Department of Finance issued draft legislation consistent with the proposals described above. As at December 31, 2006, the legislative proposals are not substantively enacted. Bonavista continues to monitor and assess the implications of the Federal Government's announcement on its existing business, and along with the Coalition of Canadian Energy Trusts, we have expressed our concerns on this proposed taxation of trusts to the Federal Government. Despite the proposed legislation's significant negative impact on the overall energy trust sector, Bonavista is still well positioned to take advantage of the opportunities arising from the changing landscape. Our success is based on the consistent application of our core philosophy and operating strategies. As such, the application of these principles will not change under the new tax regime as our team is dedicated to continue creating significant value in the oil and natural gas business for our investors.

Strengths of Bonavista Energy Trust

Since restructuring into an energy trust in July 2003, Bonavista has maintained a high level of investment activity on its asset base. This activity stems from the operational and technical focus of our trust and our ability to uncover value from our assets within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid understanding of our asset base and possess the necessary discipline and commitment to deliver profitable results to our Unitholders for the long-term. We actively participate in undeveloped land acquisitions through either Crown land sales, property purchases or farm-in opportunities, which have all continued to add to our already extensive low-risk drilling inventory. This has led to low cost reserve additions, lengthening of our reserve life index, and a growing production base. Our production base is weighted 55% towards natural gas and is geographically focused within select medium depth, multi-zone regions in Alberta, Saskatchewan and British Columbia. This base has one of the lowest operating cost structures in the oil and natural gas sector. In addition, these high working interest assets are predominantly operated by Bonavista, ensuring that operating and capital cost efficiencies are maintained and that Bonavista controls the pace of its operations. All of these attributes, combined, result in top quartile operating netbacks for Bonavista.

Our team brings a successful track record of executing low to medium risk development programs, including both asset and corporate acquisitions, along with sound financial management. Unitholders benefit from a fully internalized, industry leading cost structure, which results in one of the lowest per unit overhead cost structures in the energy trust industry. The management team, along with a strong Board of Directors, possesses extensive experience in oil and natural gas operations, corporate governance and financial management. Directors and management also own approximately 18% of the Trust, resulting in an alignment of interests with all Unitholders.

MANAGEMENT'S DISCUSSION AND ANALYSIS

Management's discussion and analysis ("MD&A") of the financial condition and results of operations should be read in conjunction with Bonavista Energy Trust's ("Bonavista" or the "Trust") consolidated interim financial statements for the three months and year ended December 31, 2006 and the audited consolidated financial statements and MD&A for the year ended December 31,2005. The following MD&A of the financial condition and results of operations was prepared at, and is dated March 14, 2007. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2006 will be available on or before March 31, 2007 through our filings on SEDAR at www.sedar.com or can be obtained from Bonavista's website at www.bonavistaenergy.com.

Basis of Presentation - The financial data presented below has been prepared in accordance with Canadian Generally Accepted Accounting Principles ("GAAP"). The reporting and the measurement currency is the Canadian dollar. For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent ("boe") using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated.

Forward-Looking Statements - Certain information set forth in this document, including management's assessment of Bonavista's 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 Bonavista'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. Bonavista's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that Bonavista will derive therefrom. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. Investors are also cautioned that cash-on-cash yield represents a blend of return of investor's initial investment and a return on investors initial investment and is not comparable to traditional yield on debt instruments where investors are entitled to full return of the principal amount of debt on maturity in addition to a return on investment through interest payments.

Non-GAAP Measurements - Within Management's discussion and analysis, references are made to terms commonly used in the oil and natural gas industry. Management uses funds from operations and the ratio of debt to funds from operations to analyze operating performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by Canadian GAAP and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with Canadian GAAP. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital and abandonment expenditures. Funds from operations per unit is calculated based on the weighted average number of trust units outstanding consistent with the calculation of net income per unit. Operating netbacks equal total revenue less royalties, transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Management uses these terms to analyze operating performance and leverage.

Operations -- Bonavista's exploitation and development program for the year ended December 31, 2006, led to the drilling of 325 wells in our four core regions with an overall success rate of 94%. This program resulted in 220 natural gas wells, 86 oil wells and 19 dry holes. For the three months ended December 31, 2006, Bonavista drilled 77 wells resulting in 51 natural gas wells, 21 oil wells and 5 dry holes. Additional emphasis was placed on drilling oil and liquids rich gas targets in our South Central Alberta core region where we have experienced excellent success. We also drilled 13 heavy oil targets in the Lloydminster area in the quarter resulting in 100% success and heavy oil production climbing to the current level of 7,800 bbls per day. Our focus on light oil, heavy oil and liquids-rich natural gas during the quarter has elevated our current oil and liquids production to approximately 24,000 bbls per day, bringing additional commodity balance to Bonavista. In addition to the exploitation and development programs, Bonavista executed 13 complementary acquisitions in its core regions in 2006.

Reserves -- Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure ("NI 51-101"). Under NI 51-101, proved reserves are defined as reserves that can be estimated with a high degree of certainty to be recoverable with a target of a 90% probability that the actual reserves recovered over time will equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%) probability that the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well defined time frame. Proved undeveloped reserves often involve infill drilling into existing pools. Of the Trust's total reserves, 83% were evaluated by independent third party engineers, GLJ Petroleum Consultants Ltd. and Ryder Scott Company Canada in their reports dated March 8, 2007 and March 5, 2007 respectively, depending on the location of the property. The balance of approximately 17% of proved and probable reserves was evaluated internally. The reserve estimates contained in the following tables represent Bonavista's interest reserves before the deduction of royalties:



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Net Present Value @
Natural Oil and Total -----------------------------
Gas Liquids Reserves 0% 5% 10%
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(bcf) (mbbls) (mboe) (millions)
Proved:
Proved
producing 370.3 46,781 108,490 $ 3,324 $ 2,367 $ 1,889
Proved non-
producing 35.2 8,082 13,957 339 262 207
Proved
undeveloped 22.7 8,780 12,560 446 252 164
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Total Proved (1) 428.2 63,643 135,006 4,109 2,881 2,260
Probable 114.7 19,972 39,084 1,340 731 489
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Total proved
and probable (1)542.9 83,615 174,091 $ 5,449 $ 3,612 $ 2,749
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Oil and
Natural Gas Liquids Total Oil Equivalent
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(bcf) (mbbls) (mboe)
Proved:
December 31, 2005 444.2 62,943 136,977
Exploitation and development 44.4 8,237 15,619
Revisions (2) (1.0) 644 480
Acquisitions 5.3 240 1,127
Dispositions - - -
Production (64.7) (8,419) (19,196)
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December 31, 2006 (1) 428.2 63,643 135,006
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Proved and probable:
December 31, 2005 539.5 79,157 169,071
Exploitation and development 67.0 12,522 23,689
Revisions (2) (6.6) 56 (1,038)
Acquisitions 7.6 299 1,566
Dispositions - - -
Production (64.7) (8,419) (19,196)
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December 31, 2006 (1) 542.9 83,615 174,091
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(1) Numbers may not add due to rounding.

(2) Revisions include economic factors.


Bonavista's 2006 year-end proved reserves totalled 135.0 mmboe, a slight decrease from the 137.0 mmboe at the year-end of 2005. Bonavista's proved and probable reserves increased by 3% to 174.1 mmboe when compared to the 169.1 mmboe at year-end 2005. Bonavista's proved and probable reserve life index ("RLI") also increased during the year to 8.9 years, with the proved RLI at 7.3 years. Finding and development costs in 2006, including changes in future development expenditures, amounted to $20.85 per boe ($18.37 per boe before changes in future development expenditures) on a proved basis and $15.29 per boe ($13.06 per boe before changes in future development expenditures) on a proved and probable basis. This generated attractive recycle ratios of 1.8:1 for proved and probable reserves and 1.3:1 for proved reserves, including revisions and changes in future development; excluding changes in future development expenditures, these recycle ratios increase to 2.1:1 and 1.5:1, respectively. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista's Annual Information Form that will be filed on SEDAR.

Financial and operating highlights -- The following is a summary of key financial and operating results for the respective periods noted:



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Three Months Years
ended ended
December 31, December 31,
2006 2005 2006 2005
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($ thousands, except per boe/Trust
Unit Amounts and where noted)

Prices:
Natural gas ($/mcf) 7.44 11.25 7.38 8.55
Oil and liquids ($/bbl) 46.52 49.45 50.42 46.39

Production:
Natural gas (mmcf/d) 174 181 177 176
Oil and liquids (bbls/d) 24,114 22,338 23,068 21,421
Total production (boe/d) 53,106 52,466 52,593 50,779

Production revenues 222,321 288,680 901,747 912,422
per boe 45.50 59.81 46.97 49.23

Royalty expense 38,985 67,295 174,903 198,956
per boe 7.98 13.94 9.11 10.73
% of Production revenue 17.5% 23.3% 19.4% 21.8%

Operating expenses 39,945 35,162 152,087 127,402
per boe 8.18 7.28 7.92 6.87

Transportation costs 10,874 7,586 40,065 28,949
per boe 2.23 1.57 2.09 1.56

General and administrative expenses 3,532 2,294 11,229 8,656
per boe 0.72 0.48 0.58 0.47

Financing expenses 7,684 5,357 26,960 23,648
per boe 1.57 1.11 1.40 1.28

Funds from operations 121,305 170,714 496,438 522,649
per boe 24.83 35.37 25.86 28.20
per unit - basic 1.17 1.72 4.86 5.41

Unit-based compensation 714 953 4,890 2,991
per boe 0.15 0.20 0.25 0.16

Depreciation, depletion and accretion 56,179 50,712 214,698 194,084
per boe 11.50 10.51 11.18 10.47

Income and other taxes (reduction) (3,424) 15,289 (25,215) 23,162
per boe (0.70) 3.17 (1.31) 1.25

Net income 67,635 103,759 301,270 302,942
per boe 13.84 21.50 15.69 16.34
per unit - basic 0.65 1.05 2.95 3.14

Distributions to Unitholders 76,296 79,212 324,016 270,827
per unit 0.90 0.99 3.87 3.47
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Production - As a direct result of Bonavista's active and successful capital programs, production for the year ended December 31, 2006 increased 4% to 52,593 boe per day when compared to 50,779 boe per day for the same period a year ago. More specifically, average natural gas production increased 1% to 177 mmcf per day from 176 mmcf per day for the same period a year ago while total oil and liquids production increased 8% to 23,068 bbls per day (comprised of 16,007 bbls per day of light and medium oil and 7,061 bbls per day of heavy oil) from 21,421 bbls per day (comprised of 15,281 bbls per day of light and medium oil and 6,140 bbls per day of heavy oil) for the same period a year ago. For the fourth quarter of 2006 production increased 1% to 53,106 boe per day from 52,466 boe per day for the same period in 2005. Natural gas production of 174 mmcf per day in the fourth quarter of 2006 decreased 4% from 181 mmcf per day for the same period a year ago, while total oil and liquids production in the fourth quarter of 2006 increased 8% to 24,114 bbls per day (comprised of 16,559 bbls per day of light and medium oil and 7,555 bbls per day of heavy oil) from 22,338 bbls per day (comprised of 16,094 bbls per day of light and medium oil and 6,244 bbls per day of heavy oil) for the same period a year ago. Our current production is approximately 52,500 boe per day consisting of 55% natural gas, 30% light and medium oil and 15% heavy oil. Bonavista's diversified commodity investment approach minimizes our dependence on any one product.

Revenues - Revenues for the year ended December 31, 2006 decreased by 1% to $901.7 million when compared to $912.4 million for the same period a year ago, primarily due to lower realized gas prices. For the year ended December 31, 2006, natural gas prices averaged $7.38 per mcf, down 14% from $8.55 per mcf for the same period in 2005. The average oil and liquids price increased 9% to $50.42 per bbl (comprised of $53.94 per bbl for light and medium oil and $42.45 per bbl for heavy oil) for the year ended December 31, 2006 from $46.39 per bbl (comprised of $51.21 per bbl for light and medium oil and $34.38 per bbl for heavy oil) for the same period in 2005. Revenues for the fourth quarter of 2006 decreased by 23% to $222.3 million from $288.7 million in the fourth quarter of 2005. This decrease is attributable to a 24% decrease in commodity prices offset by a 1% increase in production volumes on a boe basis. In the fourth quarter of 2006, our natural gas price averaged $7.44 per mcf, down 34% from $11.25 per mcf for the same period in 2005. The average oil and liquids price decreased 6% to $46.52 per bbl (comprised of $49.37 per bbl for light and medium oil and $40.28 per bbl for heavy oil) in the fourth quarter of 2006 from $49.45 per bbl (comprised of $55.52 per bbl for light and medium oil and $33.82 per bbl for heavy oil) for the same period in 2005.

Commodity hedging - As part of our financial management strategy, the Trust has adopted a disciplined commodity-hedging program. The purpose of the hedging program is to reduce volatility in the financial results, protect acquisition economics and stabilize cash flow and Unitholders' distributions against the unpredictable commodity price environment. Our hedging strategy is restricted to a maximum hedge position of 60% of forecasted production, net of royalties, and primarily utilizes costless collars in our hedging portfolio. This strategy limits our exposure to downturns in commodity prices while allowing for participation in commodity price increases. For the three months and year ended December 31, 2006, our hedging program resulted in a gain of $8.8 million and $13.5 million respectively. For the three months ended December 31, 2006, the $8.8 million gain consisted of a gain of $8.7 million on natural gas contracts and a gain of $100,000 on crude oil contracts. For the year ended December 31, 2006, the $13.5 million net gain consisted of a gain of $29.4 million on natural gas contracts and a loss of $15.9 million on crude oil contracts.

Royalties - For the year ended December 31, 2006, royalties decreased 12% to $174.9 million from $199.0 million for the same period a year ago, primarily due to lower realized natural gas prices. In addition, royalties as a percentage of revenues decreased to 19.4% in 2006 from 21.8% in 2005 primarily due to weaker natural gas prices and the impact of commodity hedging gains included in revenues. For the year ended December 31, 2006, royalties as a percentage of revenues by product were 21.1% for natural gas, 18.6% for light and medium oil and 14.1% for heavy oil. For the three months ended December 31, 2006 royalties decreased 42% from $67.3 million to $39.0 million for the same period a year ago primarily as a result of the decrease in natural gas prices and the impact of commodity hedging gains included in revenue. For similar reasons, royalties as a percentage of revenue for the fourth quarter also decreased from 23.3% in 2005 to 17.5% in 2006. For the three months ended December 31, 2006 royalties, as a percentage of revenues by product, were 18.9% for natural gas, 17.3% for light and medium oil and 12.4% for heavy oil.

Operating expenses - Operating expenses for the year ended December 31, 2006 increased 19% to $152.1 million compared to $127.4 million for the same period a year ago. Operating expenses for the fourth quarter of 2006 were $39.9 million, an increase of 13% when compared to $35.2 million incurred for the same period a year ago. The industry is continuing to experience upward pressure on all costs, primarily driven by a strong oil price, higher electrical costs and high levels of industry activity leading to higher labor costs. These factors resulted in average per unit operating costs for the year ended December 31, 2006, increasing to $7.92 per boe from $6.87 per boe in the comparable period of 2005. For 2006, per unit operating expenses by product were $1.12 per mcf for natural gas, $8.73 per bbl for light and medium oil and $10.95 per bbl for heavy oil. Per unit operating expenses for the three months ended December 31, 2006, increased to $8.18 per boe from $7.28 per boe in the same quarter of 2005. The breakdown of the fourth quarter 2006 operating expenses by product were $1.13 per mcf for natural gas, $8.85 per bbl for light and medium oil and $11.70 per bbl for heavy oil. Notwithstanding recent increases, Bonavista continues to place significant emphasis on the control of operating costs and maintains one of the lowest cash cost structures in the industry.

Transportation expenses - Transportation expenses for the year ended December 31, 2006 increased to $40.1 million ($2.09 per boe) compared to $28.9 million ($1.56 per boe) in 2005. For the three months ended December 31, 2006, transportation expenses increased 43% to $10.9 million ($2.23 per boe) as compared to $7.6 million ($1.57 per boe) for the same period last year. The increase in transportation expenses in both periods were primarily due to increasing cost pressures and higher production volumes in the fourth quarter of 2006 versus the same period in 2005. Transportation expenses by product for the year ended December 31, 2006 were $0.43 per mcf for natural gas, $0.86 per bbl for light and medium oil and $2.87 per bbl for heavy oil and for the fourth quarter of 2006 were $0.46 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.12 per bbl for heavy oil.

General and administrative expenses - General and administrative expenses, after overhead recoveries, for the year ended December 31, 2006 increased 29% to $11.2 million from $8.7 million in the same period in 2005 and increased 52% to $3.5 million for the three months ended December 31, 2006 from $2.3 million in the same period in 2005. On a per boe basis, general and administrative expenses increased 23% for the year ended December 31, 2006 to $0.58 per boe from $0.47 per boe in the same period in 2005 and increased 50% to $0.72 per boe for the three months ended December 31, 2006 from $0.48 per boe in the fourth quarter of 2005. These increases are largely due to the higher staffing levels required to manage our operations and increasing cost pressures, primarily driven by high levels of industry activity.

Through the Technical Services Agreement with NuVista Energy Ltd., Bonavista provides administrative services and receives a fee, determined on a cost recovery basis. The fee charged under this agreement was $2.3 million related to general and administrative activities rendered for the year ended December 31, 2006 and $698,000 for the three months ended December 31, 2006. In connection with its Trust Unit Incentive Rights Plan, Bonavista also recorded a unit-based compensation charge of $6.0 million and $1.8 million for the year and three months ended December 31, 2006 respectively, compared to $3.0 million and $1.0 million for the same periods of 2005. Effective January 1, 2007 fees charged under the Technical Services Agreement have been amended to reflect the separation of certain NuVista technical and administrative activities from Bonavista.

Financing expenses - Financing expenses, which include interest expense on bank debt and convertible debentures, increased to $27.0 million for the year ended December 31, 2006, from $23.6 million for the same period in 2005 and on a boe basis increased to $1.40 per boe for the year ended December 31, 2006 from $1.28 per boe in the same period in 2005. For the three months ended December 31, 2006 financing charges increased to $7.7 million from $5.4 million for the same period in 2005 and on a boe basis, increased to $1.57 per boe for the three months ending December 31, 2006 from $1.11 per boe in the same period in 2005. These increases are due to higher debt levels used to fund Bonavista's growth. Amortization and accretion expenses related to the Trust's convertible debentures for the year ended December 31, 2006 decreased to $860,000 from $1.6 million for the same period in 2005. For the three months ended December 31, 2006 amortization and accretion expenses were $197,000 as compared to $273,000 for the three months ended December 31, 2005. These decreases are largely attributable to the significant conversions of debentures into Trust Units since December 31, 2005. The amortization component reflects the charge to net income of the debenture issue costs over the term of the debenture. The fair value of the conversion option of the debentures is classified as equity. Over the term of the debentures, the carrying value will accrete to the principal balance at maturity, with the charge to accretion expense on convertible debentures. For the year ended December 31, 2006 Bonavista paid cash interest of $26.8 million compared to $24.4 million for the same period in 2005. During the fourth quarter of 2006, Bonavista paid cash interest of $7.9 million compared to $6.5 million in 2005.

Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 11% to $214.7 million for the year ended December 31, 2006 from $194.1 million in the same period of 2005. For the three months ended December 31, 2006 depreciation, depletion and accretion expenses increased by 11% to $56.2 million from $50.7 million in the same period of 2005. Both increases were due to higher production levels, higher costs of finding and developing reserves and a larger asset base in 2006. For the year ended December 31, 2006 the average cost increased to $11.18 per boe from $10.47 per boe for the same period a year ago and for the three months ended December 31, 2006 the average per unit cost increased to $11.50 per boe from $10.51 per boe in the same period of 2005. These increases are due to the higher costs of adding new reserves, which is a trend being experienced throughout the industry.

Income and other taxes - For the year ended December 31, 2006, the provision for income and other taxes was a reduction of $25.2 million compared to an expense of $23.2 million for the same period of 2005. For the three months ended December 31, 2006, the provision for income and other taxes was a reduction of $3.4 million compared to an expense of $15.3 million for the same period of 2005. The reduction in income and other taxes for the three months and year ended December 31, 2006 compared to the same periods a year ago, relate largely to the increased distributions to unitholders period over period, which are tax deductible to the Trust. In addition, the year ended December 31, 2006 includes a recovery of $14.3 million relating to a reduction in future federal and provincial income tax rates enacted during the second quarter of 2006. For the year ended December 31, 2006, Bonavista paid tax installments of $785,000 compared to $1.7 million for the same period a year ago. For the three months ended December 31, 2006, Bonavista paid tax installments of nil compared to $906,000 for the same period a year ago.

Funds from operations and net income - For the year ended December 31, 2006, Bonavista experienced a 5% decrease in funds from operations to $496.4 million ($4.86 per unit, basic) from $522.6 million ($5.41 per unit, basic) for the same period in 2005. For the three months ended December 31, 2006, Bonavista experienced a 29% decrease in funds from operations to $121.3 million ($1.17 per unit, basic) from $170.7 million ($1.72 per unit, basic) recorded in the same period in 2005. Net income for the year ended December 31, 2006, decreased 1% to $301.3 million ($2.95 per unit, basic) from $302.9 million ($3.14 per unit, basic) for the same period of 2005. Net income for the three months ended December 31, 2006, decreased to $67.6 million ($0.65 per unit, basic) and represents a 35% decrease from $103.8 million ($1.05 per unit, basic) in the fourth quarter of 2005. The decrease in funds from operations and net income for the year ended and three months ended December 31, 2006, was largely due to the decrease in natural gas prices offset somewhat by increased production volumes. The impact of lower natural gas prices on net income for the year ended December 31, 2006 was mitigated by the reductions in future income taxes.

Capital expenditures - Capital expenditures for the year ended December 31, 2006 were $316.4 million or 64% of 2006 funds from operations, which consisted of $35.8 million of net property acquisitions and $280.6 million of exploitation and development spending. For the same period in 2005, capital expenditures were $295.1 million consisting of $59.1 million of net property acquisitions and $236.0 million of exploitation and development spending. For the three month period ended December 31, 2006, capital expenditures were $58.4 million consisting of $58.7 million of exploitation and development spending and $0.3 million of property dispositions. For the same period in 2005, capital expenditures were $91.2 million, consisting of $90.2 million of exploitation and development spending and $1.0 million of net acquisitions. The increase in exploitation and development expenditures in 2006 as compared to 2005 is a direct result of a more active drilling program in Bonavista's existing core regions. While the industry is experiencing inflationary cost pressures of 10%-15% on many of its services due to high commodity prices and high industry activity levels, Bonavista successfully maintained efficient capital programs which kept production addition costs in 2006 at an attractive level of less than $30,000 per boe per day. In 2006, we were able to generate more favourable economic returns from our capital expenditure program as a direct result of our focused effort on exploitation and development activities. These activities were generated from our prospect inventory identified on our significant undeveloped land base, with less activity in the higher cost property acquisition market.

The following table outlines capital expenditures by category for the years ended December 31, 2006 and 2005:



----------------------------------------------------------------
Years ended
December 31,
2006 2005
----------------------------------------------------------------
(thousands)
Land acquisition $ 20,608 $ 16,071
Geological and geophysical 8,824 9,354
Drilling and completion 172,538 132,279
Production equipment and facilities 78,012 76,334
Other 581 1,920
----------------------------------------------------------------

Exploitation and development expenditures 280,563 235,958
Acquisitions 36,155 59,656
Dispositions (365) (562)
----------------------------------------------------------------

Net capital expenditures $ 316,353 $ 295,052
----------------------------------------------------------------
----------------------------------------------------------------


Liquidity and capital resources - As at December 31, 2006, long-term debt, including working capital deficiency, was $518 million with an attractive debt to 2006 funds from operations ratio of 1.0:1 (1.1:1 including convertible debentures). With our credit facility recently increased to $800 million in 2006, Bonavista now has $282 million of unused bank borrowing capability, leaving significant flexibility to finance future expansions in our capital programs or acquisition opportunities as they arise.

In 2007, Bonavista plans to invest approximately $300 million to expand its core regions, which will be financed through a combination of funds from operations and bank debt. The Trust is committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt. As such, the 2007 capital expenditure program is based on using a conservative amount of debt in our financing structure.

Unitholders' equity - As at December 31, 2006, Bonavista had 103,585,481 equivalent trust units outstanding. This includes 12,297,386 exchangeable shares, which are exchangeable into 18,746,504 additional trust units. The exchange ratio in effect at December 31, 2006 for exchangeable shares was 1.52443:1. As at March 14, 2007, Bonavista had 104,127,843 equivalent trust units outstanding. This includes 12,275,896 exchangeable shares which are exchangeable into 19,107,555 additional trust units. The exchange ratio in effect at March 14, 2007 for exchangeable shares was 1.55651:1. In addition, Bonavista has 3,590,425 trust unit incentive rights outstanding at March 14, 2007, with an average exercise price of $24.34 per trust unit.

As a result of minimal conversions in 2005 of exchangeable shares into trust units, Bonavista elected to redeem 10% of its exchangeable shares outstanding on March 16, 2006. This redemption allows the Trust to manage the dilution created by the compounding effect of the exchangeable shares, maintain an optimal capital and tax efficient trust structure while managing the reinvestment of capital without adverse tax consequences to the Trust and its Unitholders. In connection with this redemption, Bonavista exercised its overriding "redemption call right" to purchase such exchangeable shares from holders of record on March 16, 2006. Each redeemed Exchangeable Share was exchanged for trust units in accordance with the exchange ratio in effect at March 15, 2006, rounded to the nearest whole trust unit.

As at December 31, 2006, Unitholders' equity included $1.1 million for the ascribed value of the conversion feature of convertible debentures. This amount was determined at the time the debentures were issued and was subsequently reduced by the amounts attributed to debentures that have been converted into trust units. Of the 100,000, 7.5% convertible debentures issued on January 29, 2004 there have been 90,461 of these debentures converted into trust units, leaving 9,539 debentures with a principal amount of $9.5 million outstanding as at December 31, 2006. On December 31, 2004, the Trust issued 135,000, 6.75% convertible debentures in conjunction with a property acquisition in British Columbia. The original issue of these debentures had a principal amount of $135 million, and from the date of issuance to December 31, 2006 there have been 90,268 of these debentures converted into trust units, leaving 44,732 debentures outstanding with a principal amount of $44.7 million.

Distributions - For the year ended December 31, 2006, the Trust declared distributions of $324.0 million ($3.87 per unit), amounting to 65% of funds from operations generated during the period, while the remaining 35% of funds from operations was reinvested to fund exploitation, development and acquisition programs. For the three months ended December 31, 2006, the Trust declared distributions of $76.3 million ($0.90 per unit), amounting to 63% of funds from operations generated during the period, while the remaining 37% of funds was reinvested in exploitation, development and acquisition programs.

Bonavista announces its distribution policy on a quarterly basis. Distributions are determined by the Board of Directors and are dependent upon the commodity price environment, production levels, and the amount of capital expenditures to be financed from funds from operations. Bonavista's current monthly distribution rate is $0.30 per unit. This monthly distribution is comprised of the base distribution of $0.28 per unit plus a supplementary distribution of $0.02 per unit, due to the average realized commodity prices in excess of budget prices. The base distribution rate assumes realized commodity prices of CDN $8.00 per gj at AECO for natural gas and CDN $58.00 per bbl at Edmonton for light crude (this equates to approximately US $8.40 per mmbtu NYMEX natural gas and US $50.00 per bbl WTI crude oil). The combined base and supplementary distribution incorporates the withholding of sufficient cash flow to fund capital expenditures required to maintain or modestly grow the current production base and provide sustainable distributions in the long-term. Our long-term objective is to distribute between 50% and 60% of our cash flow. Our current distribution rate of $0.30 per unit per month places us in this range for 2007, based on the current market of commodity price futures.

Quarterly financial information - The following table highlights Bonavista's performance for the eight quarterly periods ending on March 31, 2005 to December 31, 2006:



---------------------------------------------------------------------------
2006
--------------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ------- --------
($ thousands, except
per unit amounts)
Production revenues 222,321 223,139 226,046 230,241
Net income 67,635 70,800 87,425 75,410
Net income per unit:
Basic 0.65 0.69 0.86 0.75
Diluted 0.65 0.68 0.84 0.74
---------------------------------------------------------------------------
---------------------------------------------------------------------------

---------------------------------------------------------------------------
2005
--------------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ------- --------
($ thousands, except
per unit amounts)
Production revenues 288,680 241,084 194,961 187,697
Net income 103,759 79,242 62,461 57,480
Net income per unit:
Basic 1.05 0.82 0.65 0.61
Diluted 1.01 0.79 0.64 0.60
---------------------------------------------------------------------------
---------------------------------------------------------------------------


Since its reorganization into an energy trust on July 2, 2003, Bonavista has experienced growth in production volumes in each quarter. Over the past eight quarters, production revenue peaked in the fourth quarter of 2005 reflecting the impact of increased production levels and the trend of increasing oil and natural gas commodity prices. For quarterly periods ending in 2006, production revenue and net income were lower than the last quarter of 2005, primarily due to the decrease in the price of natural gas. Over the eight quarters, production revenues have increased 18% and net income has increased 16%.

Disclosure and Internal Controls - Bonavista's President and Chief Executive Officer ("CEO") and Executive Vice President and Chief Financial Officer ("CFO") are responsible for establishing and maintaining disclosure controls and procedures, and internal controls over financial reporting as defined in MI 52-109.

Disclosure controls and procedures have been designed to ensure that information to be disclosed by Bonavista is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. Bonavista's CEO and CFO have put in place procedures to evaluate the effectiveness of the Trust's disclosure controls and procedures as at December 31, 2006 and have concluded that they provide reasonable assurance that all material information relating to the Trust is disclosed in a timely manner.

Internal controls over financial reporting are designed to provide reasonable assurance regarding the reliability of the Trust's financial reporting and compliance with generally accepted accounting principles ("GAAP"). The CEO and CFO have evaluated the Trust's internal controls over financial reporting as at December 31, 2006 based on the framework in "Internal Control -- Integrated Framework" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") and have concluded they are sufficiently designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with GAAP. During the quarter ended December 31, 2006, there have been no changes to the Trust's internal controls over financial reporting that have materially, or are reasonably likely to, materially affect the internal controls over financial reporting.

Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute assurance, that the objectives of the control systems are met.

Proposed Taxation of Income Trusts - On October 31, 2006, the Federal Government announced proposals pertaining to the taxation of distributions from publicly traded Canadian income trusts, royalty trusts and partnerships. The proposals include a 31.5% tax imposed on income before distributions at the trust level and taxed to the taxable Canadian investor, effectively as a dividend. If enacted, the proposals would apply to the Trust effective January 1, 2011. On December 21, 2006, the Department of Finance issued draft legislation consistent with the proposals described above. As at December 31, 2006, the legislative proposals are not substantively enacted. Bonavista continues to monitor and assess the implications of the Federal Government's announcement on its existing business, and along with the Coalition of Canadian Energy Trusts, we have expressed our concerns on this proposed taxation of trusts to the Federal Government. Despite the proposed legislation's significant negative impact on the overall energy trust sector, Bonavista is still well positioned to take advantage of the opportunities arising from the changing landscape. Our success is based on the consistent application of our core philosophy and operating strategies. As such, the application of these principles will not change under the new tax regime as our team is dedicated to continue to create significant value in the oil and natural gas business for our investors.

We encourage our Unitholders to read the full transcript of the government's plan at www.fin.gc.ca/news06/06-061e.html and consult their personal financial and tax advisors regarding potential tax consequences based on their individual circumstances. Unitholders may also express their views directly to the Federal Minister of Finance, whose contact information is available at www.fin.gc.ca/admin/contact-e.html.

Update on Regulatory and Financial Reporting Matters - In April, 2005, a series of new accounting standards were released which established guidance for the recognition and measurement of financial instruments. These new standards include Section 1530 "Comprehensive Income", Section 3855 "Financial Instruments -- Recognition and Measurements", and Section 3865 "Hedges". The new standards also resulted in a number of significant consequential amendments to other accounting standards to accommodate the new sections. The standards require all applicable financial instruments to be classified into one of several categories including; financial assets and financial liabilities held for trading, held-to-maturity investments, loans and receivables, available-for-sale financial assets, or other financial liabilities. The financial instruments are then included on a company's balance sheet and measured at fair value, cost or amortized value, depending on the classification. Subsequent measurement and recognition of changes in value of the financial instruments also depends on the initial classification. These standards are effective for interim and annual financial statements for fiscal years beginning on or after October 1, 2006 and must be implemented simultaneously. The Trust will adopt the new standards on January 1, 2007 and will no longer apply hedge accounting.

OUTLOOK

The Trust continues to benefit from all the same qualities that drove the success of Bonavista Petroleum Ltd. as a public company prior to its conversion into an energy trust. We continue to apply similar proven principles and execute our strategy in a disciplined and cost-effective manner. The foundation of this strategy is to actively pursue low to medium risk drilling opportunities on the extensive undeveloped land base within our geographically concentrated areas of operations. Despite spending a record amount on exploitation and development activities in 2006 and drilling over 300 wells, our inventory of quality drilling opportunities continues to increase heading into 2007. This increase in inventory can be directly attributed to the detailed and tireless work of our talented Bonavista technical team, who possess a strong commitment and a solid understanding of the Western Canadian Sedimentary Basin. We also continue to search for strategic acquisition opportunities where we can add value utilizing our own technical expertise. This period of extreme commodity price volatility and market uncertainty could easily benefit Bonavista in the future due to its proven track record and strong balance sheet. Our prudent approach to capital investment has been very effective in the past and together with our steadfast commitment to adding Unitholder value and attention to detail will provide the foundation for the future success of the Trust. Today our activity, efficiency, productivity and profitability remain among the strongest levels in our nine and a half year history.

For 2007, Bonavista's capital budget includes drilling approximately 260 to 280 wells on existing lands in Bonavista's four core regions. Similar to 2006, these locations generally consist of low to medium risk prospects drilled within close proximity of company owned and operated infrastructures. The capital required to complete this drilling program and our complementary acquisition program is estimated to be between $280 and $300 million and should result in modest growth in average daily production levels to approximately 53,000 to 54,000 boe per day in 2007.

We are proud of our achievements over the past nine and a half years and are very excited about the growing opportunities that exist for Bonavista in the future. We would like to thank our employees for their significant effort and their continued enthusiasm and excitement as we pursue these opportunities. Despite the recent consternation in the Canadian Income Trust equity market resulting from the announcement of the Federal Government's proposed "Tax Fairness Plan", Bonavista's value creation process has not changed. Throughout many business cycles and changes in the business environment, Bonavista has thrived. Our success is based on the consistent application of our core philosophy and operating strategies. This practice will not change under the new government tax regime as our team remains dedicated to adding Unitholder value in the oil and natural gas business, regardless of the landscape.



--------------------------------------------------------------------------
--------------------------------------------------------------------------
Consolidated Balance Sheets December 31, December 31,
(thousands) 2006 2005
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(unaudited)

Assets:
Accounts receivable $ 116,251 $ 105,173
Oil and natural gas
properties and equipment 1,910,359 1,788,398
Goodwill 41,321 41,321
--------------------------------------------------------------------------
$ 2,067,931 $ 1,934,892
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Accounts payable and accrued liabilities $ 122,376 $ 133,080
Long-term debt 512,323 343,802
Other long-term obligations 1,846 4,896
Convertible debentures 51,170 87,866
Asset retirement obligations 96,324 82,819
Future income taxes 153,639 178,919
Unitholders' equity:
Unitholders' capital 834,625 769,629
Exchangeable shares 75,121 92,370
Contributed surplus 4,973 2,456
Convertible debentures 1,117 1,892
Accumulated earnings 214,417 237,163
--------------------------------------------------------------------------
1,130,253 1,103,510
--------------------------------------------------------------------------
$ 2,067,931 $ 1,934,892
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Consolidated Statements of Operations and Accumulated Earnings
(thousands, except per unit amounts)
Three Months Years
ended ended
December 31, December 31,
2006 2005 2006 2005
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 222,321 $ 288,680 $ 901,747 $ 912,422
Royalties (38,985) (67,295) (174,903) (198,956)
--------------------------------------------------------------------------
183,336 221,385 726,844 713,466
--------------------------------------------------------------------------
Expenses:
Operating 39,945 35,162 152,087 127,402
Transportation 10,874 7,586 40,065 28,949
General and administrative 3,532 2,294 11,229 8,656
Financing 7,684 5,357 26,960 23,648
Amortization and accretion
of convertible debentures 197 273 860 1,632
Unit-based compensation 714 953 4,890 2,991
Depreciation, depletion
and accretion 56,179 50,712 214,698 194,084
--------------------------------------------------------------------------
119,125 102,337 450,789 387,362
--------------------------------------------------------------------------
Income before taxes 64,211 119,048 276,055 326,104
Income and other
taxes (reductions) (3,424) 15,289 (25,215) 23,162
--------------------------------------------------------------------------
Net income 67,635 103,759 301,270 302,942
Accumulated earnings,
beginning of year 223,078 212,616 237,163 205,048
Distributions declared (76,296) (79,212) (324,016) (270,827)
--------------------------------------------------------------------------
Accumulated earnings,
end of period $ 214,417 $ 237,163 $ 214,417 $ 237,163
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Net income per unit -
basic $ 0.65 $ 1.05 $ 2.95 $ 3.14
--------------------------------------------------------------------------
--------------------------------------------------------------------------
Net income per unit -
diluted $ 0.65 $ 1.01 $ 2.90 $ 3.05
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.


--------------------------------------------------------------------------
Consolidated Statements of Cash Flows
(thousands) Three Months Years
ended ended
December 31, December 31,
2006 2005 2006 2005
--------------------------------------------------------------------------
--------------------------------------------------------------------------
(unaudited)
Cash provided by (used in):
Operating Activities:
Net income $ 67,635 $ 103,759 $ 301,270 $ 302,942
Items not requiring cash
from operations:
Depreciation, depletion
and accretion 56,179 50,712 214,698 194,084
Amortization and accretion
of convertible debentures 197 273 860 1,632
Unit-based compensation 714 953 4,890 2,991
Future income taxes
(reductions) (3,420) 15,017 (25,280) 21,000
Asset retirement expenditures (2,862) (1,970) (5,694) (3,948)
Changes in non-cash working
capital items (23,987) 15,175 (15,694) (15,214)
--------------------------------------------------------------------------
94,456 183,919 475,050 503,487
--------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net
of issue costs 1,096 620 5,936 4,234
Distributions (78,763) (77,144) (325,064) (262,108)
Change in long-term debt 45,276 (30,115) 168,521 34,708
Changes in non-cash working
capital items (276) 1,376 121 (1,191)
--------------------------------------------------------------------------
(32,667) (105,263) (150,486) (224,357)
--------------------------------------------------------------------------
Investing Activities:
Business acquisition - - (25,800) (44,800)
Exploitation and development (58,744) (90,189) (280,563) (235,958)
Property acquisitions 87 (997) (10,355) (14,856)
Property dispositions 258 - 365 562
Changes in non-cash working
capital items (3,390) 12,530 (8,211) 15,922
--------------------------------------------------------------------------
(61,789) (78,656) (324,564) (279,130)
--------------------------------------------------------------------------
Change in cash - - - -
Cash, beginning of period - - - -
--------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
--------------------------------------------------------------------------
--------------------------------------------------------------------------
See accompanying notes to consolidated financial statements


BONAVISTA ENERGY TRUST

Notes to Consolidated Financial Statements

For the year ended December 31, 2006 (unaudited)

Structure of the Trust and Basis of Presentation:

Bonavista Energy Trust (the "Trust" or "Bonavista") is an open-ended unincorporated investment trust governed by the laws of the Province of Alberta. The Trust was established on July 2, 2003 under a Plan of Arrangement entered into by the Trust, Bonavista Petroleum Ltd. ("BPL") and its subsidiaries and partnerships and NuVista Energy Ltd. ("NuVista"). Under the Plan of Arrangement, a wholly-owned subsidiary of the Trust amalgamated with BPL and became the successor company. The Trust has two significant subsidiaries in which it owns 100% of the common shares of BPL (excluding the exchangeable shares -- see note 5) and 100% of the units of Bonavista Trust (2003) ("BT"). The activities of these entities are financed through interest bearing notes from the Trust and third party debt as described in the notes to the consolidated financial statements. The business of the Trust is carried on through the entities owned by the subsidiaries of the Trust, Bonavista Petroleum, a general partnership ("BP") and Bonavista Energy Limited Partnership ("BELP"). The net income of the Trust is generated from interest on notes advanced to its subsidiaries, royalty payments on oil and natural gas assets owned by BP, as well as any dividends or distributions paid by its subsidiaries. The Trustee must declare payable to the Trust Unitholders all of the taxable income of the Trust.

The unaudited consolidated financial statements include the accounts of the Trust and its wholly-owned subsidiaries and partnerships, and have been prepared by management in accordance with Canadian Generally Accepted Accounting Principles. The interim consolidated financial statements and notes should be read in conjunction with the consolidated financial statements for the year ended December 31, 2005. Certain amounts have been reclassified to conform with the current period's presentation.

1. Business Relationships:

Under the Plan of Arrangement, Bonavista entered into a Technical Services Agreement ("TSA") with NuVista. Under the TSA, Bonavista receives payment for certain technical and administrative services provided by it to NuVista on a cost recovery basis. Bonavista and NuVista are considered related as two directors of NuVista, one of whom is NuVista's chairman, are directors and officers of Bonavista and a director and an officer of NuVista are also officers of Bonavista. Pursuant to the TSA, there were fees of $2.3 million charged relating to general and administrative activities and $180,000 of fees were charged relating to capital expenditure activities for the year ended December 31, 2006 (2005 -- $1.7 million and $180,000 respectively). As at December 31, 2006, amounts receivable from NuVista was $2.7 million (2005 -- $1.3 million).

On June 1, 2006, Bonavista acquired oil and natural gas properties through a partnership for cash consideration of $25.8 million and included the results of operations from the date of the acquisition. A director and an officer of Bonavista are related parties of the vendor. Bonavista purchased these oil and natural gas properties through a series of transactions, with the properties being acquired in an existing partnership owned approximately 24% by BP and 76% by NuVista Energy Ltd. In conjunction with the acquisition, Bonavista recognized $800,000 of asset retirement obligations.

2. Asset retirement obligations:

The Trust's asset retirement obligations result from net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities. The Trust estimates the total undiscounted amount of expenditures required to settle its asset retirement obligations is approximately $475.2 million (2005 - $408.1 million) which will be incurred over the next 51 years. The majority of the costs will be incurred between 2010 and 2036. A credit-adjusted risk-free rate of 7.5% (2005 -- 7.5%) and an inflation rate of 2% (2005 -- 2%) was used to calculate the fair value of the asset retirement obligations.

A reconciliation of the asset retirement obligations is provided below:



--------------------------------------------------------
Years ended
December 31,
2006 2005
--------------------------------------------------------
(thousands)
Balance, beginning of year $ 82,819 $ 58,531
Accretion expense 6,279 4,650
Liabilities incurred 11,332 15,285
Liabilities acquired 1,588 1,337
Liabilities settled (5,694) (3,948)
Changes in assumptions - 6,964
--------------------------------------------------------
Balance, end of year $ 96,324 $ 82,819
--------------------------------------------------------
--------------------------------------------------------


3. Long-term debt:

The Trust has an $800 million credit facility with a syndicate of chartered banks. This facility is an unsecured, covenant-based, extendible revolving facility and includes a $50 million working capital facility. The facility provides that advances may be made by way of prime rate loans, bankers' acceptances and/or US dollar LIBOR advances. These advances bear interest at the banks' prime rate and/or at money market rates plus a stamping fee. The facility is a three year revolving credit and may, at the request of the trust with the consent of the lenders, be extended on an annual basis. At present, no principal payments are required under the credit facility until August 10, 2009 subject to extension by the lenders.

Financing expenses include interest on bank loans of $22.4 million (2005 - $13.2 million) and convertible debentures of $4.5 million (2005 - $10.4 million). For the year ended December 31, 2006, Bonavista paid cash interest of $26.8 million (2005 - $24.4 million).

Under the terms of the credit facility, the Trust has provided the covenant that its consolidated senior debt borrowing will not exceed three times net income before interest, taxes and depreciation, depletion and accretion; consolidated total debt will not exceed three and one half times consolidated net income before interest, taxes and depreciation, depletion and accretion; and consolidated senior debt borrowing will not exceed one-half of consolidated total debt plus consolidated unitholders' equity of the Trust.

4. Convertible debentures:

The debt component of the debentures has been recorded net of the fair value of the conversion feature and issue costs. The fair value of the conversion feature of the debentures in Unitholders' equity at the date of issue was $4.7 million. The issue costs are amortized to earnings over the term of the obligation and the debt component of the obligation is adjusted for the amortization as well as for the portion of issue costs relating to conversions. The debt portion is accreted over the term of the obligation to the principal value on maturity with a corresponding charge to net income. The following table sets out the convertible debenture activities to December 31, 2006:



--------------------------------------------------------------------------
Debt Equity
Component Component
--------------------------------------------------------------------------
(thousands)
Balance, December 31, 2005 $ 87,866 $ 1,892
Accretion 115 -
Issue expenses related to conversions
to trust units 629 -
Amortization of issue expenses 745 -
Conversion to trust units (38,185) (775)
--------------------------------------------------------------------------
Balance, December 31, 2006 $ 51,170 $ 1,117
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5. Unitholders' capital and exchangeable shares:

a) Authorized:

Unlimited number of voting trust units.

b) Issued and outstanding:

(i) Trust Units:



--------------------------------------------------------------------------
Number of
Units Amount
--------------------------------------------------------------------------
(thousands)
Balance, December 31, 2005 80,288 $ 769,629
Issued on conversion of convertible debentures 1,491 38,185
Issued on conversion of exchangeable shares 2,526 17,249
Issued upon exercise of trust unit incentive rights 534 5,936
Issue costs, related to debenture conversions - (629)
Adjustment to equity component of debenture on
conversion - 775
Unit-based compensation - 3,480
--------------------------------------------------------------------------
Balance, December 31, 2006 84,839 $ 834,625
--------------------------------------------------------------------------
--------------------------------------------------------------------------

(ii) Contributed surplus:

---------------------------------------------------
Amount
---------------------------------------------------
(thousands)
Balance, December 31, 2005 $ 2,456
Unit-based compensation expense 4,890
Unit-based compensation capitalized 1,107
Exercise of trust unit incentive rights (3,480)
---------------------------------------------------
Balance, December 31, 2006 $ 4,973
---------------------------------------------------
---------------------------------------------------


(iii) Exchangeable shares:

Pursuant to the Plan of Arrangement, 15,999,999 exchangeable shares were authorized and issued. The exchangeable shares of BPL are convertible into trust units based on the exchange ratio, which is adjusted monthly, to reflect the distribution paid on the trust units. As a result, distributions are not paid on the exchangeable shares.



--------------------------------------------------------------------------
Years ended December 31,
2006 2005
Number Amount Number Amount
--------------------------------------------------------------------------
(thousands)
Opening balance before
restatement 14,101 $ 92,370 14,391 $ 40,686
Net income attributable to
non-controlling interest - - - 52,505
--------------------------------------------------------------------------
Opening balance after restatement 14,101 92,370 14,391 93,191
Exchanged for trust units (1,804) (17,249) (290) (821)
--------------------------------------------------------------------------
Balance 12,297 $ 75,121 14,101 $ 92,370
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--------------------------------------------------------------------------
Exchange ratio, end of year 1.52443 - 1.36525 -
--------------------------------------------------------------------------
Trust units issuable on exchange 18,747 $ 75,121 19,251 $ 92,370
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The Trust retroactively applied the amended accounting abstract "Exchangeable Securities issued by a Subsidiary of an Income Trust" whereby the exchangeable shares issued by the Trust's subsidiary are reflected as a non-controlling interest on the consolidated balance sheet, as the conditions required to treat exchangeable shares as equity were not met at the time the exchangeable shares were issued. Net income was reduced by the amount of net income attributed to the non-controlling interest.

The non-controlling interest on the consolidated balance sheet at December 31, 2004 consisted of the book value of exchangeable shares issued to Bonavista Petroleum Ltd. shareholders at the time of the Arrangement, plus net earnings attributable to the exchangeable shares based on the trust units issuable for exchangeable shares in proportion to total trust units issued and issuable each period end, less exchangeable shares redeemed.

Subsequent to December 31, 2004 the terms of the exchangeable shares were amended whereby the holders of exchangeable shares are only convertible into Trust Units. As a result the exchangeable shares meet the conditions for presentation as equity of the Trust and are included as Unitholders' equity subsequent to December 31, 2004.

c) Trust unit incentive rights plan:

The Trust has a unit incentive rights plan that allows the Trust to issue rights to acquire trust units to directors, officers, employees and service providers. The Trust is authorized to issue up to 4,882,225 unit rights, however, the number of trust units reserved for issuance upon exercise of the rights shall not at any time exceed 5% of the aggregate number of issued and outstanding trust units of the Trust. Trust unit incentive right exercise prices are equal to the market price for the trust units on the date that the unit rights are granted. If certain conditions are met, the exercise price per unit may be calculated by deducting from the grant price the aggregate of all distributions, on a per unit basis, made by the Trust after the grant date. The trust unit incentive rights granted under the plan vest over a four-year period and expire one year after each vesting date.



----------------------------------------------------------------------
Average
Number of Trust Exercise
Unit Incentive Rights Price
----------------------------------------------------------------------
Balance, December 31, 2005 2,937,525 $ 21.86
Granted 1,514,100 33.92
Exercised (534,450) (11.11)
Cancelled (218,700) (26.34)
Reduction in exercise price - (3.42)
----------------------------------------------------
Balance, December 31, 2006 3,698,475 $ 24.67
----------------------------------------------------------------------
----------------------------------------------------------------------
Exercisable, December 31, 2006 496,200 $ 14.20
----------------------------------------------------------------------
----------------------------------------------------------------------


d) Unit-based compensation:

The Trust uses the fair value based method for the determination of the unit-based compensation costs. The fair value of each incentive right granted was estimated on the date of grant using the modified Black-Scholes option-pricing model. In the pricing model, the risk free interest was 3.5% (2005 -- 3.5%); volatility of 25% (2005 -- 25%); a forfeiture rate of 10% (2005 -- 10%) and an expected life of 4.5 years. The fair value of the options granted in 2006 averages $7.96 (2005 - $7.43) per incentive right.

e) Per unit amounts:

For the year ended December 31, 2006, there were 102,156,057 (2005 -- 96,520,456) weighted average Trust Units outstanding. For the purpose of calculating net income per unit on a diluted basis, the net income as reported has been increased by the interest and accretion on the convertible debentures for the respective period. On a diluted basis, there were 105,614,514 (2005 -- 103,066,753) weighted average Trust Units outstanding after giving effect for dilutive instruments. Diluted per unit calculations for the year ended December 31, 2006 includes an additional 3,458,457 Trust Units (2005 - 6,546,297) for the dilutive impact of the unit rights incentive plan and convertible debentures.

6. Hedge instruments:

a) Financial instruments:

As at December 31, 2006, the Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:



---------------------------------------------------------------------------
Volume Average Price Term
---------------------------------------------------------------------------
10,000 gjs/d CDN$7.50 - CDN$10.63 - AECO January 1, 2007 - March 31, 2007
20,000 gjs/d CDN$6.44 - CDN$9.00 - AECO April 1, 2007 - October 31, 2007
5,000 bbls/d US$60.70 - US$82.33 - WTI January 1, 2007 - March 31, 2007
6,000 bbls/d US$63.67 - US$83.05 - WTI April 1, 2007 - June 30, 2007
5,000 bbls/d US$62.25 - US$79.78 - WTI July 1, 2007 - September 30, 2007
5,000 bbls/d US$62.05 - US$80.16 - WTI October 1, 2007 - December 31, 2007
1,000 bbls/d US$62.00 - US$75.30 - WTI January 1, 2008 - December 31, 2008
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As at December 31, 2006, the market value of these financial instruments was a gain of approximately $4.2 million.

b) Physical purchase contracts:

As at December 31, 2006, the Trust has entered into direct sale costless collars to sell natural gas as follows:



---------------------------------------------------------------------------
Average Price
Volume (CDN$ - AECO) Term
---------------------------------------------------------------------------
45,000 gjs/d $ 7.86 - $ 10.92 January 1, 2007 - March 31, 2007
20,000 gjs/d $ 6.75 - $ 9.31 April 1, 2007 - October 31, 2007
5,000 gjs/d $ 7.50 - $ 10.75 November 1, 2007 - March 31, 2008
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INVESTOR INFORMATION

Bonavista Energy Trust is a natural gas weighted energy trust which is committed to maintaining its emphasis on operating high quality oil and natural gas properties, delivering consistent distributions to unitholders and ensuring financial strength and sustainability.

Corporate information provided herein contains forward-looking information. The reader is cautioned that assumptions used in the preparation of such information, particularly those pertaining to cash distributions, production volumes, commodity prices, operating costs and drilling results, which are considered reasonable by Bonavista at the time of preparation, may be proven to be incorrect. Actual results achieved during the forecast period will vary from the information provided herein and the variations may be material. There is no representation by Bonavista that actual results achieved during the forecast period will be the same in whole or in part as those forecast.

Contact Information

  • Bonavista Energy Trust
    Keith A. MacPhail
    President & CEO
    (403) 213-4300
    or
    Ronald J. Poelzer
    Executive Vice President & CFO
    (403) 213-4300
    Website: www.bonavistaenergy.com