Bonavista Energy Trust
TSX : BNP.UN

Bonavista Energy Trust

March 12, 2008 16:58 ET

Bonavista Energy Trust Announces 2007 Year End Results

CALGARY, ALBERTA--(Marketwire - March 12, 2008) - 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, 2007.



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Highlights
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Three Months Years
ended ended
December 31, December 31,
2007 2006 2007 2006
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Financial
($ thousands, except per unit)

Production revenues 242,361 220,484 911,346 910,079

Funds from operations (i) 127,778 121,305 502,783 496,438
Per unit (i)(ii) 1.20 1.17 4.76 4.86

Distributions declared 77,136 76,296 307,401 324,016
Per unit 0.90 0.90 3.60 3.87
Percentage of funds from
operations (i) 60% 63% 61% 65%

Net income 63,631 67,635 218,187 301,270
Per unit (ii) 0.60 0.65 2.07 2.95

Total assets 2,242,057 2,067,931

Long-term debt, including working
capital deficiency 723,003 518,448

Unitholders' equity 1,060,967 1,130,253

Capital expenditures:
Exploitation and development 58,440 58,744 267,660 280,563
Acquisitions, net (425) (345) 98,696 35,790

Weighted average outstanding
equivalent trust units:
(thousands) (ii)
Basic 106,762 103,533 105,543 102,156
Diluted 109,102 106,304 108,075 105,615
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Operating

(boe conversion - 6:1 basis)

Production:
Natural gas (mmcf/day) 170 174 171 177
Oil and liquids (bbls/day) 24,775 24,114 24,034 23,068
Total oil equivalent (boe/day) 53,029 53,106 52,505 52,593

Product prices: (iii)
Natural gas ($/mcf) 6.74 7.44 6.95 7.38
Oil and liquids ($/bbl) 58.04 46.52 54.40 50.42

Operating expenses ($/boe) 8.58 8.18 8.47 7.92

General and administrative
expenses ($/boe) 0.74 0.72 0.70 0.58

Cash costs ($/boe) (iv) 11.56 10.47 11.01 9.92

Operating netback ($/boe) (v) 29.17 27.12 28.77 27.85
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December 31,
Highlights (cont'd) 2007 2006
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Drilling (gross wells) 216 325
Natural gas 108 220
Oil 97 86
Average success rate 95% 94%

Reserves:
Proved:
Natural gas (bcf) 427.1 428.2
Oil and liquids (mbbls) 63,724 63,643
Total oil equivalent (mboe) 134,911 135,006
Proved and probable:
Natural gas (bcf) 561.0 542.9
Oil and liquids (mbbls) 85,955 83,615
Total oil equivalent (mboe) 179,454 174,091
% Proved producing 62% 62%
% Proved 75% 78%
% Probable 25% 22%
Net present value of future cash flow before
income taxes ($ millions):
0% discount rate 6,116 5,449
5% discount rate 4,116 3,612
10% discount rate 3,154 2,749
Reserve life index (years):
Proved 7.3 7.3
Proved and probable 9.2 8.9

Finding, development and acquisition costs -
proved and probable ($/boe):
Including changes in future development expenditures 15.91 15.29
Excluding changes in future development expenditures 14.94 13.06

Recycle ratio - proved and probable: (v)
Including changes in future development expenditures 1.8 1.8
Excluding changes in future development expenditures 1.9 2.1
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Three Months ended
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December 31, September 30, June 30, March 31,
Trust Unit Trading Statistics 2007 2007 2007 2007
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($ per unit, except volume)
High 31.85 31.38 33.54 31.89
Low 24.14 27.25 29.12 25.90
Close 28.50 29.02 30.60 30.85
Average Daily Volume 275,892 177,752 216,676 230,630
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NOTES:

(i) Management uses funds from operations to analyze operating
performance, distribution coverage and leverage. Funds from
operations as presented do 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 units outstanding consistent with the calculation of
net income per unit.

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

(iii) Product prices include realized gains or losses on financial
instruments.

(iv) Cash costs equal the total of operating, general and administrative,
and financing expenses.

(v) Operating netback equals production revenues including realized gains
or losses on financial instruments, less royalties, transportation and
operating expenses, calculated on a boe basis. Operating netback is
used in the recycle ratio calculation.


MESSAGE TO UNITHOLDERS

Bonavista Energy Trust ("Bonavista" or the "Trust") is pleased to report to its unitholders (the "Unitholders") its consolidated financial and operating results for the three months and year ended December 31, 2007. The results for the fourth quarter of 2007 represents eighteen 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 2007 are a testament to the validity and effectiveness of an operationally and technically focused energy trust. The fourth quarter and annual results for 2007 are also highlighted by an active and successful drilling and acquisitions program, which has led to attractive reserve addition costs. These costs have also benefited from somewhat lower service costs with the slowdown in industry activity in the latter half of 2007. This current environment creates the opportunity for Bonavista to continue to differentiate itself by posting solid financial results in an ever-changing economic landscape.
Other significant accomplishments for Bonavista in 2007 include:

- Operationally, production volumes held steady at 52,505 boe per day during 2007 versus 52,593 boe per day in 2006 and have increased 52% from 34,600 boe per day since commencement as an energy trust on July 2, 2003. Bonavista's current production rate is approximately 55,500 boe per day;

- Added 24.5 mmboe of proved and probable reserves during 2007, which replaced annual production by 1.3 times and also improved the Trust's proved and probable reserve life index to 9.2 years from 8.9 years in 2006. These reserves were added at an attractive finding, development and acquisition cost, including changes in future development expenditures, of $19.77 per boe on a proved basis ($19.21 per boe excluding changes in future development expenditures) and $15.91 per boe on a proved and probable basis ($14.94 per boe excluding changes in future development expenditures). A strong proved and probable recycle ratio of 1.8:1 (1.5:1 proved) was achieved in 2007 as a result of the low level of finding, development and acquisition costs. Overall in 2007, Bonavista increased proved and probable reserves by 3% to 179.5 mmboe while spending 73% of funds from operations on exploitation, development and acquisition expenditures;

- Maintained an active capital program during 2007, investing $267.7 million in exploitation and development activities. Bonavista drilled 216 wells with an overall 95% success rate, and we spent $98.7 million on 10 synergistic acquisitions within our core regions;

- Completed a strategic property acquisition in the Willesden Green area which complimented our existing assets with a high working interest ownership and operatorship of facilities and infrastructure. On January 14, 2008 we completed an additional acquisition of producing and undeveloped oil and natural gas properties to further complement our operations in this area as part of our 2008 capital program. We have assembled a new core property over the past two years, currently producing over 5,000 boe per day;

- Continued to actively participate at crown land sales, investing $33.2 million in land activity during the year compared to $20.6 million in 2006, and further enhancing our future drilling prospect inventory to more than three years;

- Invested $18.0 million to acquire 49 sections of undeveloped land through Crown and Freehold purchases in the light oil Bakken trend in the greater Viewfield area of southeast Saskatchewan. We have currently drilled five wells on these lands with promising results to date;

- Generated funds from operations of $502.8 million ($4.76 per unit) in 2007 and recorded strong profitability with net income of $218.2 million ($2.07 per unit). This resulted in an attractive average return on equity of 20% and a strong net income to funds from operations ratio of 43%;

- Established a new $1.0 billion 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 2008 and beyond; and

- Delivered top decile total returns, within the energy trust industry, to our Unitholders in 2007 and currently have a cash on cash yield of 12%. In addition, Bonavista has delivered cumulative distributions of $1.2 billion or $15.51 per trust unit since inception of our Trust in July 2003.

On October 25, 2007, the Government of Alberta announced its proposal for a new royalty framework in Alberta. The proposed changes to the Alberta Crown Royalty framework are to take effect on January 1, 2009. Bonavista will continue to analyze the information that becomes available with respect to the new crown royalty framework. Based upon initial documentation, royalty rates will increase substantially on medium depth natural gas, high productivity natural gas and light oil production in Alberta and as a result the economics of these opportunities have been negatively impacted under a higher price commodity scenario. The Government of Alberta is currently monitoring this negative impact and have indicated that, should their original decision result in unintended consequences, the framework could be reviewed and adjusted as required to re-stimulate activity. Bonavista will continue to assess the impact that the new royalty framework will have on our existing operations, including our capital allocations for 2008 and beyond. Bonavista has a strong history of remaining flexible and ensuring that it allocates capital to those projects delivering the highest rate of return and will continue to do so under this new royalty regime.

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, growing production by over 50% since that time. This activity stems from the operational and technical focus of our Trust and the ability to uncover value from our assets within the Western Canadian Sedimentary Basin. Our experienced and consistent 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 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 balanced 54% in favour of natural gas and 46% towards oil and liquids 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 trust 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 attractive 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 costs 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, management and employees 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") audited consolidated financial statements and MD&A for the year ended December 31, 2007. The following MD&A of the financial condition and results of operations was prepared at, and is dated March 12, 2008. Our audited consolidated financial statements, Annual Report, and other disclosure documents for 2007 will be available on or before March 30, 2008 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. A boe may be misleading, particularly if used in isolation. A boe conversion of 6 Mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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, changes in environmental, tax and royalty legislation, 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 production revenue and realized gains or losses on financial instruments, 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, 2007 led to the drilling of 216 wells in our four core regions with an overall success rate of 95%. This program resulted in 108 natural gas wells, 97 oil wells and 11 dry holes. Bonavista continues to emphasize deeper, higher impact drilling opportunities within the Northeast British Columbia and South Central Alberta core regions where we have experienced excellent success and attractive finding and development costs over this period. These activities have also lengthened our reserve life index and the predictability in our overall production base. We drilled 43 heavy oil targets in the Lloydminster area in 2007 resulting in 100% success and relatively stable heavy oil production of 7,500 bbls per day. In addition to the exploitation and development program, Bonavista executed 10 complementary acquisitions in its core regions during 2007.

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 net present value reserves, 81% were evaluated by independent third party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") and Ryder Scott Company Canada in their reports dated February 26th, 2008 and March 4th, 2008 respectively, depending on the location of the property. The balance of approximately 19% 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 373.0 49,729 111,887 $3,704 $2,713 $2,187
Proved non-producing 27.3 5,745 10,302 262 201 161
Proved undeveloped 26.8 8,249 12,722 492 297 203
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Total proved (i) 427.1 63,724 134,911 4,457 3,211 2,551
Probable 133.9 22,231 44,543 1,659 906 603
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Total proved and
probable (i) 561.0 85,955 179,454 $6,116 $4,116 $3,154
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Natural Oil and Total
Gas Liquids Reserves
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(bcf) (mbbls) (mboe)
Proved:
December 31, 2006 428.2 63,643 135,006
Exploitation and development 35.2 6,279 12,139
Revisions (ii) 2.9 (509) (28)
Acquisitions, net 23.2 3,085 6,959
Production (62.4) (8,773) (19,165)
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December 31, 2007 (i) 427.1 63,724 134,911
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Proved and probable:
December 31, 2006 542.9 83,615 174,091
Exploitation and development 45.7 8,637 16,260
Revisions (ii) 7.1 (1,212) (32)
Acquisitions, net 27.7 3,688 8,300
Production (62.4) (8,773) (19,165)
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December 31, 2007 (i) 561.0 85,955 179,454
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(i) Numbers may not add due to rounding.
(ii) Revisions include economic factors.


Bonavista's 2007 year-end proved reserves totalled 134.9 mmboe, essentially unchanged compared to the 135.0 mmboe at the year-end of 2006. Bonavista's proved and probable reserves increased by 3% to 179.5 mmboe when compared to the 174.1 mmboe at year-end 2006. Bonavista's proved and probable reserve life index ("RLI") also increased during the year to 9.2 years, with the proved RLI at 7.3 years. Finding, development and acquisition costs in 2007, including changes in future capital expenditures, amounted to $19.77 per boe ($19.21 per boe before changes in future capital expenditures) on a proved basis and $15.91 per boe ($14.94 per boe before changes in future capital expenditures) on a proved and probable basis. The aggregate of the exploration and development costs incurred in the most recent financial year and the change during the year in estimated future development costs generally will not reflect total finding and development costs relating to reserve additions for that year. Bonavista generated attractive recycle ratios of 1.8:1 for proved and probable reserves and 1.5:1 for proved reserves, including revisions and changes in future development expenditures; excluding changes in future development expenditures, the proved and probable recycle ratio increased to 1.9:1 and the proved recycle ratio remains unchanged at 1.5:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista's Annual Information Form that will be filed on SEDAR.

On October 25, 2007, the Government of Alberta announced its proposal for a New Royalty Framework ("NRF") in Alberta. The NRF is anticipated to take effect January 1, 2009, this will result in the Trust's royalty rates for the low value sensitivity case to increase by less than one percent. The net present value of the Trust's total reserves will decrease by less than two percent using GLJ's forecasted prices as at January 1, 2008 and a 10% discount rate.


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,
2007 2006 2007 2006
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($ thousands, except per boe/Trust
Unit Amounts and where noted)

Product prices:
Natural gas ($/mcf) 6.74 7.44 6.95 7.38
Oil and liquids ($/bbl) 58.04 46.52 54.40 50.42

Production:
Natural gas (mmcf/d) 170 174 171 177
Oil and liquids (bbls/d) 24,775 24,114 24,034 23,068
Total production (boe/d) 53,029 53,106 52,505 52,593

Production revenues 242,361 220,484 911,346 910,079
per boe 49.68 45.13 47.55 47.41

Royalties 42,809 38,985 155,586 174,903
per boe 8.77 7.98 8.12 9.11
% of Production revenues 17.7% 17.7% 17.1% 19.2%

Operating expenses 41,867 39,945 162,371 152,087
per boe 8.58 8.18 8.47 7.92

Transportation expenses 10,364 10,874 41,397 40,065
per boe 2.12 2.23 2.16 2.09

General and administrative expenses 3,620 3,532 13,335 11,229
per boe 0.74 0.72 0.70 0.58

Financing expenses 10,915 7,684 35,209 26,960
per boe 2.24 1.57 1.84 1.40

Funds from operations 127,778 121,305 502,783 496,438
per boe 26.19 24.83 26.24 25.86
per unit - basic 1.20 1.17 4.76 4.86

Unit-based compensation 2,809 714 7,351 4,890
per boe 0.58 0.15 0.38 0.25

Depreciation, depletion and
accretion 60,467 56,179 231,945 214,698
per boe 12.39 11.50 12.10 11.18

Income taxes (reduction) (30,831) (3,424) (535) (25,215)
per boe (6.32) (0.70) (0.03) (1.31)

Net income 63,631 67,635 218,187 301,270
per boe 13.04 13.84 11.39 15.69
per unit - basic 0.60 0.65 2.07 2.95

Distributions declared 77,136 76,296 307,401 324,016
per unit 0.90 0.90 3.60 3.87
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Production - Overall for 2007 production was 52,505 boe per day, largely unchanged when compared to 52,593 boe per day for the same period a year ago. More specifically, average natural gas production decreased 3% to 171 mmcf per day in 2007 from 177 mmcf per day for the same period a year ago, while total oil and liquids production increased 4% to 24,034 bbls per day (comprised of 16,486 bbls per day of light and medium oil and 7,548 bbls per day of heavy oil) from 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) for the same period in 2006. This trend was the result of a decision made earlier in 2007 to emphasize crude oil projects over natural gas projects due to the favorable oil economics. For the fourth quarter of 2007, production was also essentially unchanged at 53,029 boe per day when compared to 53,106 boe per day for the same period in 2006. Natural gas production decreased 2% to 170 mmcf per day in the fourth quarter of 2007 from 174 mmcf per day for the same period a year ago, while total oil and liquids production increased 3% to 24,775 bbls per day in the fourth quarter of 2007 (comprised of 16,825 bbls per day of light and medium oil and 7,950 bbls per day of heavy oil) from 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) for the same period a year ago. Our current production is approximately 55,500 boe per day consisting of 54% natural gas, 33% light and medium oil and 13% heavy oil. Bonavista's diversified commodity investment approach minimizes our dependence on any one product.

Revenues - Revenues, excluding gains and losses on financial instruments, for the year ended December 31, 2007 increased slightly to $911.3 million when compared to $910.1 million for the same period a year ago. For the year ended December 31, 2007, our natural gas price including realized gains on financial instruments averaged $6.95 per mcf, a decrease of 6% from $7.38 per mcf for the same period in 2006. The average oil and liquids price increased 8% to $54.40 per bbl (comprised of $58.61 per bbl for light and medium oil and $45.20 per bbl for heavy oil) for the year ended December 31, 2007 from $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 same period in 2006. Revenues, excluding gains and losses on financial instruments, for the fourth quarter of 2007 increased by 10% to $242.4 million when compared to $220.5 million in the fourth quarter of 2006 due to higher average commodity prices. In the fourth quarter of 2007, natural gas prices averaged $6.74 per mcf, down 9% from $7.44 per mcf for the same period in 2006. The average oil and liquids price increased 25% to $58.04 per bbl (comprised of $62.32 per bbl for light and medium oil and $48.99 per bbl for heavy oil) in the fourth quarter of 2007 from $46.52 per bbl (comprised of $49.37 per bbl for light and medium oil and $40.28 per bbl for heavy oil) for the same period in 2006.

Commodity price risk management - As part of our financial management strategy, Bonavista has adopted a disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations against unpredictable commodity prices and protect acquisition economics. Bonavista's Board of Directors has approved a commodity price risk management limit of 60% of forecast production, net of royalties, primarily using costless collars. Our strategy of using costless collars limits Bonavista's exposure to downturns in commodity prices, while allowing for participation in commodity price increases.

Prior to January 1, 2007, Bonavista accounted for all of our financial contracts as hedges and included realized gains or losses in revenues. On January 1, 2007, with the adoption of new accounting standards for financial instruments and hedging, Bonavista discontinued hedge accounting treatment for our financial commodity derivative contracts. Accordingly, realized and unrealized gains on these financial instruments are recognized in the current period. See note 1 of the audited consolidated financial statements for the year ended December 31, 2007.

For the year ended December 31, 2007, our risk management program on financial instruments resulted in a net loss of $45.7 million, consisting of a realized loss of $665,000 and an unrealized loss of $45.1 million. The realized loss of $665,000 consisted of a $5.2 million gain on natural gas commodity derivative contracts and a $5.9 million loss on crude oil commodity derivative contracts. For the three months ended December 31, 2007, our risk management program on financial instruments resulted in a net loss of $36.5 million, consisting of a realized loss of $5.0 million and an unrealized loss of $31.5 million. The realized loss of $5.0 million consisted of a $1.7 million gain on natural gas commodity derivative contracts and a $6.7 million loss on crude oil commodity derivative contracts.

The following is a summary of commodity price risk management contracts as at December 31, 2007.

i) Financial instruments:

The Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:



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Volume Average Price Term
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5,000 gjs/d CDN$ 7.50 - January 1, 2008 -
CDN$ 10.55 - AECO March 31, 2008
5,000 gjs/d CDN$ 7.00 - April 1, 2008 -
CDN$ 9.00 - AECO October 31, 2008
7,000 bbls/d US$ 65.43 - January 1, 2008 -
US$ 78.58 - WTI December 31, 2008
1,000 bbls/d CDN$ 49.00 - January 1, 2008 -
CDN$ 57.00 - Bow River December 31, 2008
2,000 bbls/d US$ 65.00 - January 1, 2009 -
US$ 80.50 - WTI March 31, 2009
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As at December 31, 2007, the market deficit of these derivative financial instruments was approximately $45.1 million.

ii) Physical purchase contracts:

The Trust has entered into direct sale costless collars to sell natural gas as follows:



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Volume Average Price (CDN$ - AECO) Term
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20,000 gjs/d $ 7.75 - $ 10.53 January 1, 2008 - March 31, 2008
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Subsequent to December 31, 2007, the Trust has entered into the following commodity contracts:

i) Financial instruments:

The Trust has hedged by way of costless collars to sell natural gas (gjs/d) and crude oil (bbls/d) as follows:



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Volume Average Price Term
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20,000 gjs/d CDN$ 7.38 - April 1, 2008 -
CDN$ 8.46 - AECO October 31, 2008
2,000 bbls/d CDN$ 61.00 - April 1, 2008 -
CDN$ 71.75 - Bow River December 31, 2008
1,000 bbls/d US$ 85.00 - January 1, 2009 -
US$ 105.60 - WTI December 31, 2009
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ii) Physical purchase contracts:

The Trust has entered into direct sale costless collars to sell natural gas as follows:



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Volume Average Price (CDN$ - AECO) Term
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45,000 gjs/d $ 7.19 - $ 8.36 April 1, 2008 - October 31, 2008
25,000 gjs/d $ 7.65 - $ 9.65 November 1, 2008 - March 31, 2009
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Royalties - For the year ended December 31, 2007, royalties decreased 11% to $155.6 million from $174.9 million for the same period a year ago, primarily due to lower natural gas prices and favourable crown royalty adjustments relating to prior periods. In addition, royalties as a percentage of revenue including realized gains and losses on financial instruments decreased to 17.1% from 19.4% in 2006 primarily due to similar reasons. For the year ended December 31, 2007, royalties by product, as a percentage of revenue including realized gains and losses on financial instruments were 17.6% for natural gas, 16.8% for light and medium oil and 16.0% for heavy oil. For the year ended December 31, 2006, royalties by product, as a percentage of revenue including realized gains and losses on financial instruments 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, 2007, royalties increased 10% to $42.8 million from $39.0 million for the same period a year ago, largely attributed to increased heavy oil royalties resulting from the payout of two oil sand royalty projects. In addition, royalties as a percentage of revenue including realized gains and losses on financial instruments for the fourth quarter of 2007 also increased from 17.5% in 2006 to 18.0% in 2007 for similar reasons discussed above. For the three months ended December 31, 2007, royalties by product as a percentage of revenues including realized gains and losses on financial instruments were 18.1% for natural gas, 17.8% for light and medium oil and 18.4% for heavy oil. For the three months ended December 31, 2006, royalties by product, as a percentage of revenue including realized gains and losses on financial instruments 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, 2007 increased 7% to $162.4 million compared to $152.1 million for the same period a year ago. Operating expenses for the fourth quarter of 2007 increased 5% to $41.9 million compared to $39.9 million for the same period a year ago. Over the past several months, operating costs have shown signs of stabilizing as we have experienced a slow-down in industry activity due to lower natural gas prices and the proposed changes to the Alberta Royalty framework. Average per unit operating costs for the year ended December 31, 2007 increased to $8.47 per boe which is up 7% from $7.92 per boe in the comparable period of 2006. For 2007, per unit operating expenses by product were $1.17 per mcf for natural gas, $9.16 per bbl for light and medium oil and $12.36 per bbl for heavy oil compared to $1.12 per mcf for natural gas, $8.73 per bbl for light and medium oil and $10.95 per bbl for heavy oil for 2006. For the three months ended December 31, 2007, operating costs increased 5% to $8.58 per boe from $8.18 per boe in the comparable period of 2006. Operating costs by product for the fourth quarter of 2007 were $1.16 per mcf for natural gas, $9.31 per bbl for light and medium oil and $12.72 per bbl for heavy oil compared to $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 the year over year increases, Bonavista continues to place significant emphasis on the control of operating costs and is continuing to pursue cost reduction initiatives.

Transportation expenses - Transportation expenses for the year ended December 31, 2007 increased to $41.4 million ($2.16 per boe) compared to $40.1 million ($2.09 per boe) in 2006. For the three months ended December 31, 2007, transportation expenses decreased 5% to $10.4 million ($2.12 per boe) when compared to $10.9 million ($2.23 per boe) for the same period last year. The increase in transportation expenses year to date was primarily due to the increase in trucking costs per barrel for heavy oil along with an increase in heavy oil volumes. These increases have been offset by a decrease in natural gas transportation due to the expiry of certain firm export service obligations. Transportation expenses for the fourth quarter of 2007 decreased as compared to the same period in 2006 primarily as a result of lower realized gas transportation costs. Transportation expenses by product for the year ended December 31, 2007 were $0.44 per mcf for natural gas, $0.92 per bbl for light and medium oil and $3.18 per bbl for heavy oil compared to $0.43 per mcf for natural gas, $0.86 per bbl for light and medium oil and $2.87 per bbl for heavy oil for the same period in 2006. For the fourth quarter of 2007, transportation expenses by product were $0.43 per mcf for natural gas, $0.86 per bbl for light and medium oil and $3.19 per bbl for heavy oil compared to $0.46 per mcf for natural gas, $0.85 per bbl for light and medium oil and $3.12 per bbl for heavy oil for the same period a year ago.

General and administrative expenses - General and administrative expenses, after overhead recoveries, for the year ended December 31, 2007 increased 19% to $13.3 million from $11.2 million in the same period in 2006 and increased 3% to $3.6 million for the three months ended December 31, 2007 from $3.5 million in the same period in 2006. On a per boe basis, general and administrative expenses increased 21% for the year ended December 31, 2007 to $0.70 per boe from $0.58 per boe in the same period in 2006 and increased 3% for the three months ended December 31, 2007 to $0.74 per boe from $0.72 per boe in the same period in 2006. This increase is largely due to the higher staffing levels required to manage our operations and increasing general cost pressures currently experienced throughout the industry. In addition, through a services agreement with NuVista Energy Ltd., Bonavista provides certain administrative activities. The fee charged under this agreement was $1.4 million for the year ended December 31, 2007 as compared to $2.3 million in the same period in 2006 and $400,000 for the three months ended December 31, 2007 as compared to $698,000 in 2006. In connection with its Trust Unit Incentive Rights Plan, Bonavista also recorded a unit-based compensation charge of $7.4 million and $2.8 million for the year and three months ended December 31, 2007 respectively, compared to $4.9 million and $714,000 for the same periods in 2006.

Financing expenses - Financing expenses, which include interest expense on long-term debt and convertible debentures, increased to $35.2 million for the year ended December 31, 2007, from $27.0 million for the same period in 2006 and on a boe basis increased to $1.84 per boe for the year ended December 31, 2007 from $1.40 per boe in the same period in 2006. For the three months ended December 31, 2007, financing expenses increased to $10.9 million from $7.7 million for the same period in 2006 and on a boe basis increased to $2.24 per boe for the three months ended December 31, 2007 from $1.57 per boe for the same period in 2006. These increases are due to higher interest rates and increased debt levels used to fund Bonavista's capital program. Amortization and accretion expenses related to the Trust's convertible debentures for the year ended December 31, 2007 decreased to $777,000 from $860,000 for the same period in 2006. For the three months ended December 31, 2007 amortization and accretion expenses decreased to $192,000 from $197,000 for the same period in 2006. This decrease is largely attributable to the conversion of debentures into Trust Units since December 31, 2006. 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, 2007 Bonavista paid cash interest of $35.4 million compared to $26.8 million for the same period in 2006. During the fourth quarter of 2007, Bonavista paid cash interest of $11.3 million compared to $7.9 million in 2006.

Depreciation, depletion and accretion expenses - Depreciation, depletion and accretion expenses increased 8% to $231.9 million for the year ended December 31, 2007 from $214.7 million for the same period in 2006. For the three months ended December 31, 2007 depreciation, depletion and accretion expenses also increased by 8% to $60.5 million from $56.2 million in the same period of 2006. Both increases were due to higher costs of finding and developing reserves and a larger asset base in 2007. For the year ended December 31, 2007 the average cost increased to $12.10 per boe from $11.18 per boe for the same period in 2006 and for the three months ended December 31, 2007 the average cost increased to $12.39 per boe from $11.50 per boe for the same period a year ago. The increase in depreciation, depletion and accretion expenses are due to increased costs associated with adding reserves. Over the past few years our industry has seen tremendous cost escalation due to the heavy demand for oilfield services, in particular drilling and service rig activities. These costs are showing signs of alleviating, the result of an industry-wide slowdown due to the lower natural gas prices realized throughout the past year and the uncertainty surrounding the new Alberta Royalty framework.
Income taxes - For the year ended December 31, 2007, the provision for income taxes was a recovery of $535,000 compared to a recovery of $25.2 million for the same period of 2006. For the three months ended December 31, 2007, the provision for income tax was a recovery of $30.8 million compared to a recovery of $3.4 million for the same period in 2006. The income tax provision for the year ended December 31, 2007 includes a $36.4 million future income tax charge resulting from recent changes to income tax legislation substantively enacted in the second and fourth quarters of 2007 that modify the taxation of certain flow through entities, including mutual fund trusts and their unitholders. The provision arose as the book basis of the assets and liabilities held in the Trust and a subsidiary trust exceeded their tax basis. Previously, future income taxes were recorded only on the temporary differences in the corporate subsidiaries of the Trust. In addition, the provision for the year ended December 31, 2007 includes a recovery of $9.6 million related to tax rate reductions enacted during the second and fourth quarters of 2007. Bonavista made no cash payments relating to installments for either of the three months and year ended December 31, 2007, compared to nil and $785,000, respectively, for the same periods a year ago.

Funds from operations, net income and comprehensive income - For the year ended December 31, 2007, Bonavista experienced a 1% increase in funds from operations to $502.8 million ($4.76 per unit, basic) from $496.4 million ($4.86 per unit, basic) for the same period in 2006. For the three months ended December 31, 2007, Bonavista experienced a 5% increase in funds from operations to $127.8 million ($1.20 per unit, basic) from $121.3 million ($1.17 per unit, basic) for the same period in 2006. Funds from operations increased for the year and three months ended December 31, 2007 primarily due to higher realized oil and liquids product prices and higher oil and liquids volumes. Net income for the year ended December 31, 2007, decreased 28% to $218.2 million ($2.07 per unit, basic) from $301.3 million ($2.95 per unit, basic) for the same period of 2006. The decrease is largely due to higher depletion and depreciation expenses and the recognition of unrealized losses on financial instruments and the higher provisions for income taxes. For the three months ended December 31, 2007, net income decreased 6% to $63.6 million ($0.60 per unit, basic) from $67.6 million ($0.65 per unit, basic) for the same period in 2006. The decrease in net income, prior to the tax provision to reflect the enactment of the taxation changes, for the year ended December 31, 2007, was largely due to a recovery relating to the reduction in future federal and provincial income tax rates enacted during the fourth quarter of 2006 and the recognition of unrealized losses on financial instruments. Other comprehensive income for the year ended December 31, 2007 included a charge of $6.0 million, (2006 - nil) relating to the amortization of the amount recognized in accumulated other comprehensive income on January 1, 2007 for the fair value of financial instruments on adoption of the new accounting standards for financial instruments. This resulted in total comprehensive income for the year ended December 31, 2007 of $212.2 million (2006 - $301.3 million). Other comprehensive income for the three months ended December 31, 2007 included a charge of $2.5 million, (2006 - nil) relating to the amortization of the amount recognized in accumulated other comprehensive income on January 1, 2007 for the fair value of financial instruments on adoption of the new accounting standards for financial instruments. This resulted in total comprehensive income for the three months ended December 31, 2007 of $61.1 million (2006 - $67.6 million).

The following table is a reconciliation of a non-GAAP measure, funds from operations, to its nearest measure prescribed by GAAP:



----------------------------------------------------------------------------
Calculation of Funds From Operations: Three Months ended Years ended
December 31, December 31,
2007 2006 2007 2006
----------------------------------------------------------------------------
(thousands)
Cash flow from operating activities $ 95,459 $ 94,456 $473,021 $475,050
Increase in non-cash working capital 27,535 23,987 21,424 15,694
Asset retirement expenditures 4,784 2,862 8,338 5,694
----------------------------------------------------------------------------

Funds from operations $127,778 $121,305 $502,783 $496,438
----------------------------------------------------------------------------
----------------------------------------------------------------------------


Capital expenditures - Capital expenditures for the year ended December 31, 2007 were $366.4 million, which consisted of $267.7 million of exploitation and development spending and $98.7 million of net property acquisitions. The total capital expenditures of $366.4 million was slightly higher than budget due to an increase in our crown land expenditures and planned $8.5 million disposition of northeast Alberta natural gas assets to a junior oil and natural gas company that was not consummated. For the same period in 2006, capital expenditures were $316.4 million consisting of $280.6 million of exploitation and development spending and $35.8 million of net property acquisitions. Capital expenditures for the three month period ended December 31, 2007 were $58.0 million, consisting of $58.4 million on exploitation and development spending and $425,000 of dispositions. For the same period in 2006 capital expenditures were $58.4 million, consisting of $58.7 million of exploitation and development spending and $345,000 of dispositions. With the industry currently experiencing cost reductions in many of its services due to lower industry activity levels, Bonavista too is benefiting with its active drilling program which is generating production addition costs at attractive levels. Entering 2008, we continue to generate favourable economic returns from our capital expenditure program as a direct result of the recent decrease in service costs coupled with strengthening commodity prices.

The following table outlines capital expenditures by category for the years ended December 31, 2007 and 2006:



------------------------------------------------------------------
Years ended
December 31,
2007 2006
------------------------------------------------------------------
(thousands)

Land acquisitions $ 33,211 $ 20,608
Geological and geophysical 9,811 8,824
Drilling and completion 139,578 172,538
Production equipment and facilities 84,444 78,012
Other 616 581
------------------------------------------------------------------
Exploitation and development expenditures 267,660 280,563
Acquisitions 100,806 36,155
Dispositions (2,110) (365)
------------------------------------------------------------------

Net capital expenditures $ 366,356 $ 316,353
------------------------------------------------------------------
------------------------------------------------------------------


Liquidity and capital resources - As at December 31, 2007, long-term debt including working capital deficiency, was $723.0 million with an attractive debt to 2007 funds from operations ratio of 1.4:1 (1.5:1 including convertible debentures). With our bank credit facility recently increased to $1.0 billion in August 2007, Bonavista has $277.0 million of unused bank borrowing capability, leaving significant flexibility to finance future expansions in our capital programs or acquisition opportunities as they arise.

In 2008, Bonavista plans to invest approximately $400 to $420 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 2008 capital expenditure program is based on using a conservative amount of debt in our financing structure.

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.

Subsequent event - On January 14, 2008, we completed the acquisition of producing and undeveloped oil and natural gas properties in the Willesden Green area of our South Central Alberta core regions and the Fireweed area located in our Northeast British Columbia core region for proceeds of $167 million. The acquisition added approximately 3,800 boe per day; comprised of 14 mmcf per day of natural gas, 700 bbls per day of associated natural gas liquids and 800 bbls per day of light crude oil.

Unitholders' equity - As at December 31, 2007, Bonavista had 106.8 million equivalent trust units outstanding. This includes 12.2 million exchangeable shares, which are exchangeable into 21.1 million trust units. The exchange ratio in effect at December 31, 2007 for exchangeable shares was 1.72244:1. As at March 12, 2008, Bonavista had 107.7 million equivalent trust units outstanding. This includes 12.2 million exchangeable shares, which are exchangeable into 21.5 million trust units. The exchange ratio in effect at March 12, 2008 for exchangeable shares was 1.76049:1. In addition, Bonavista has 3.3 million trust unit incentive rights outstanding at March 12, 2008, with an average exercise price of $27.26 per trust unit.

As at December 31, 2007, Unitholders' equity included $1.1 million for the ascribed value of the conversion feature of the 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 92,206 of these debentures converted into trust units, leaving 7,794 debentures with a principal amount of $7.8 million outstanding as at December 31, 2007. 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 $135.0 million, and from the date of issuance to December 31, 2007 there have been 91,698 of these debentures converted into trust units, leaving 43,302 debentures outstanding with a principal amount of $43.3 million.

Distributions - Bonavista's distribution policy is constantly monitored and is dependent upon its forecasted operations, funds from operations, debt levels and capital expenditures. One of the paramount objectives of the Trust is to be a sustainable entity, which is defined as maintaining both production and reserves over an extended period of time. This is accomplished by retaining sufficient funds from operations to replace the reserves that have been produced. With these considerations, for the year ended December 31, 2007 the Trust declared distributions of $307.4 million compared to $324.0 million in the same period in 2006. For the three months ended December 31, 2007 the Trust declared distributions of $77.1 million compared to $76.3 million in the same period in 2006.

The following table illustrates the relationship between cash flow provided from operating activities and distributions declared, as well as net income and distributions declared. Net income includes significant non-cash charges that do not impact cash flow. For the year and three months ended December 31, 2007, the non-cash charges amounted to $284.6 million and $64.1 million respectively compared to $195.2 million and $53.7 million for the same periods in 2006. Net income also includes fluctuations in future income taxes due to changes in tax rates and tax rules. In addition, other non-cash charges, such as depreciation, depletion and accretion and unrealized gains and losses on financial instruments, do not represent the actual cost of maintaining our productive capacity given the natural declines associated with oil and gas assets. In these instances, where distributions exceed net income, a portion of the cash distribution paid to Unitholders may be considered an economic return of Unitholders' capital.



----------------------------------------------------------------------------
Three Months Years
ended ended
December 31, December 31,
Distribution Analysis 2007 2006 2007 2006
----------------------------------------------------------------------------
(thousands)

Cash flow provided from operating
activities $ 95,459 $ 94,456 $ 473,021 $ 475,050
Net income 63,631 67,635 218,187 301,270
Distributions declared 77,136 76,296 307,401 324,016
Excess of cash flow provided from
operating activities over
distributions declared 18,323 18,160 165,620 151,034
Excess (shortfall) of net income
over distributions declared (13,505) (8,661) (89,214) (22,746)
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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 trust unit. This monthly distribution is comprised of the base distribution of $0.28 per trust 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 $60.00 per barrel at Edmonton for light crude (this equates to approximately US $9.30 per mmbtu for NYMEX natural gas and US $60.00 per barrel for WTI crude oil). The combined base and supplementary distribution incorporates the withholding of sufficient funds from operations 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 funds from operations. Our current distribution rate of $0.30 per trust unit per month places us in this range for 2008, 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, 2006 to December 31, 2007:



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2007
---------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ------- ---------
($ thousands, except per
unit amounts)
Production revenues 242,361 219,885 223,878 225,222
Net income 63,631 58,990 33,936 61,630
Net income per unit:
Basic 0.60 0.56 0.32 0.59
Diluted 0.59 0.55 0.32 0.59
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----------------------------------------------------------------------------

----------------------------------------------------------------------------
2006
---------------------------------------------
December 31 September 30 June 30 March 31
----------- ------------ ------- ---------
($ thousands, except per
unit amounts)
Production revenues 220,484 227,270 229,492 232,833
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
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----------------------------------------------------------------------------


Production revenue, excluding gains and losses on financial instruments were 4% higher in the fourth quarter of 2007 versus the first quarter of 2006, primarily due to both slightly higher production volumes and average product prices. Net income decreased 16% in the fourth quarter of 2007 as compared to the first quarter of 2006. The decrease in net income in the fourth quarter of 2007 is attributed to a $31.5 million charge to net income to reflect the unrealized losses on financial instruments. The decrease in net income in the second quarter of 2007 is attributable to the non-cash future income tax charge to net income of $41.0 million to reflect recent changes to income tax legislation, substantially enacted in the second quarter of 2007.

Financial Reporting Update - Effective January 1, 2007, Bonavista adopted Canadian Institute of Chartered Accountants ("CICA") Section 3855, "Financial Instrument Recognition and Measurement" Section 3865, "Hedges" Section 1530, "Comprehensive Income", and Section 3861, "Financial Instruments - Disclosure and Presentation". These standards have been adopted prospectively. See note 1 to the consolidated financial statements. On December 1, 2006 the CICA issued three new accounting standards, Section 1535, "Capital Disclosures", Section 3862, "Financial Instruments - Disclosures" and Section 3863, "Financial Instruments - Presentation". These three new standards will require additional disclosure in the Trust's financial statements commencing January 1, 2008. The Trust will be required to adopt Section 3064 "Goodwill and Intangible Assets" on January 1, 2009. Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for complete convergence of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The Trust will continue to monitor and assess the impact of the planned convergence of Canadian GAAP with IFRS.

Update on Regulatory Matters - On October 25, 2007, the Government of Alberta released its much anticipated New Royalty Framework ("NRF"). The NRF was the government's response to a report issued September 18, 2007 by the Alberta Royalty Review Panel, which was commissioned by the Government of Alberta to perform a review of the province's royalty system to, in their words, ensure that the people of Alberta were receiving their "Fair Share" for the resources being extracted by the oil and gas industry. The full NRF is available at www.energy.gov.ab.ca. The NRF is anticipated to take effect January 1, 2009, this will result in the Trust's royalty rates for the low value sensitivity case to increase by less than one percent. Using GLJ's forecasted prices as at January 1, 2008 and a 10% discount rate will decrease the net present value of the Trust's reserves by less than two percent. Given the recent strength in commodity prices, the NRF will significantly impact the net present value of the Trust's reserves, however, at this time the full extent of the impact is not determinable, as the proposed framework has not been enacted.

Environmental Matters - On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the "Action Plan") also known as ecoACTION, which includes the Regulatory Framework for Air Emissions. This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy-using products. Regarding large industry and industry related projects, the Government's Action Plan intends to achieve the following: (i) an absolute reduction of 150 megatonnes in greenhouse gas emissions by 2020 by imposing mandatory targets; and (ii) air pollution from industry is to be cut in half by 2015 by setting certain targets. New facilities using cleaner fuels and technologies will have a grace period of three years. In order to facilitate the companies' compliance with the Action Plan's requirements, while at the same time allowing them to be cost-effective, innovative and adopt cleaner technologies, certain options are provided. These are: (i) in-house reductions; (ii) contributions to technology funds; (iii) trading of emissions with below-target emission companies; (iv) offsets; and (v) access to Kyoto's Clean Development Mechanism.

On March 10, 2008, the Government of Canada released "Turning the Corner - Taking Action to Fight Climate Change" (the "Updated Action Plan") which provides some additional guidance with respect to the Government of Canada's plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050. The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including oil and natural gas producers. The Updated Action Plan is intended to force industry to reduce greenhouse gas emissions and to create a carbon emissions trading market, including an offset system, to provide incentive to reduce greenhouse gas emissions and establish a market price for carbon. The Updated Action Plan provides for: (i) mandatory reductions of 18% from the 2006 baseline starting in 2010 and by an additional 2% in subsequent years for existing facilities; and (ii) new facilities built between 2004 and 2011 will have mandatory emissions standards based upon clean fuel standards (natural gas) with a 2% reduction below the third years intensity levels. For the upstream oil and natural gas industry the Updated Action Plan also provides for a company threshold of 10,000 boe per day and a facility threshold of 3,000 tonnes of CO2.

On March 8, 2007, the Alberta Government introduced Bill 3, the Climate Change and Emissions Management Amendment Act, which intends to reduce greenhouse gas emission intensity from large industries. Bill 3 states that facilities emitting more than 100,000 tonnes of greenhouse gases a year must reduce their emission intensity by 12% starting July 1, 2007; if such reduction is not initially possible the companies owning the large emitting facilities will be required to pay $15 per tonne for every tonne above the 12% target. These payments will be deposited into an Alberta-based technology fund that will be used to develop infrastructure to reduce emissions or to support research into innovative climate change solutions. As an alternate option, large emitters can invest in projects outside of their operations that reduce or offset emissions on their behalf, provided that these projects are based in Alberta. Prior to investing, the offset reductions offered by a prospective operation, must be verified by a third party to ensure that the emission reductions are real.

Given the evolving nature of the debate related to climate change and the control of greenhouse gases and resulting requirements, at this time it is not possible to predict the impact of those requirements on Bonavista's operations and financial condition although it is thought to be an immaterial amount.

OUTLOOK

As we progress into our eleventh year since restructuring the Company in 1997, we continue to benefit from all of the same qualities that drove the success of Bonavista Petroleum Ltd. as a public company and an energy trust. We apply similar proven principles and execute our strategy in a disciplined and cost-effective manner much the same as in 1997 when we started on this mission of value creation. 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 a very active exploitation and development program over the past year, the quality and quantity of our drilling opportunities continues to increase as we transition from 2007 into 2008. This increase in inventory can be directly attributed to the detailed and tireless work of our talented 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 commodity price volatility and market uncertainty should benefit Bonavista in the near future due to its proven track record of timely acquisitions and our strong balance sheet. In late 2007, we witnessed acquisition prices decreasing to a level that compares favourably with our cost of adding reserves organically and we acted on this by committing to a $167 million natural gas-weighted property acquisition, which was completed in January 2008. 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 continue to provide the foundation for the future success of the Trust. Today our activity, efficiency, productivity and profitability remain among the strongest levels in our ten year history.

As a result of completing this strategic property acquisition in the first quarter of 2008, Bonavista is pleased to announce that its Board of Directors has approved an expanded operating and capital program for 2008. However, in light of the current volatility in equity and commodity markets, Bonavista has decided to take a somewhat conservative approach and proceed with a base capital budget of $400 to $420 million which includes no further acquisition capital beyond the $167 million acquisition. The remainder of the capital program will be allocated to Bonavista's exploration, exploitation and development programs which includes drilling approximately 200 to 220 wells on existing and recently acquired lands in our core regions. It is anticipated that the base capital program should result in Bonavista's 2008 production volumes averaging approximately 54,000 to 54,500 boe per day. This level of production factors in significant downtime anticipated in the second and third quarters, primarily due to two major third party plant turnarounds. Assuming current commodity prices in the futures market are realized, Bonavista's 2008 cashflow should increase to approximately $640 to $650 million. Bonavista has currently identified over 680 drilling prospects on its current land base and may accelerate the drilling of some of these prospects in the latter half of 2008, should market conditions warrant. In the interim, Bonavista will proceed prudently and methodically with its stated drilling program in the first half of the year to allow for maximum financial flexibility and remain opportunistic to further expand its capital program on additional acquisitions and/or drilling opportunities.

We are extremely proud of our achievements over our past ten 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 passage of legislation in the Canadian House of Commons on the taxation of distributions from certain publicly traded Canadian trusts and the introduction of the NRF by the Government of Alberta, 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. Our corporate structure may ultimately change by 2011 when the new tax laws are introduced but our proven strategy will not change under this new tax regime nor the provincial government's new royalty regime, as our team remains dedicated to add Unitholder value in the oil and natural gas business, regardless of the changing landscape.



----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Balance Sheets December 31, December 31,
(thousands) 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Assets:
Current assets:
Accounts receivable $ 112,226 $ 116,251
Future income tax asset 13,517 -
----------------------------------------------------------------------------
125,743 116,251
Oil and natural gas properties and
equipment 2,074,993 1,910,359
Goodwill 41,321 41,321
----------------------------------------------------------------------------
$ 2,242,057 $ 2,067,931
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Unitholders' Equity:
Current liabilities:
Accounts payable and accrued liabilities $ 91,034 $ 122,376
Unrealized financial instruments 45,058 -
----------------------------------------------------------------------------
136,092 122,376
Long-term debt and other obligations 712,654 514,169
Convertible debentures 48,830 51,170
Asset retirement obligations 116,893 96,324
Future income taxes 166,621 153,639
Unitholders' equity:
Unitholders' capital 850,631 834,625
Exchangeable shares 74,710 75,121
Contributed surplus 9,369 4,973
Convertible debentures 1,054 1,117
Accumulated earnings 125,203 214,417
----------------------------------------------------------------------------
1,060,967 1,130,253
----------------------------------------------------------------------------
$ 2,242,057 $ 2,067,931
----------------------------------------------------------------------------
----------------------------------------------------------------------------



Consolidated Statements of Operations, Comprehensive Income and Accumulated
Earnings

(thousands, except per Three Months ended Years ended
unit amounts) December 31, December 31,
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(unaudited)
Revenues:
Production $ 242,361 $ 220,484 $ 911,346 $ 910,079
Royalties (42,809) (38,985) (155,586) (174,903)
----------------------------------------------------------------------------
199,552 181,499 755,760 735,176
----------------------------------------------------------------------------
Realized gains (losses) on
financial instruments (5,008) 1,837 (665) (8,332)
Unrealized (losses) on
financial instruments (31,510) - (45,058) -
----------------------------------------------------------------------------
163,034 183,336 710,037 726,844
----------------------------------------------------------------------------
Expenses:
Operating 41,867 39,945 162,371 152,087
Transportation 10,364 10,874 41,397 40,065
General and administrative 3,620 3,532 13,335 11,229
Financing 10,915 7,684 35,209 26,960
Unit-based compensation 2,809 714 7,351 4,890
Depreciation, depletion and
accretion 60,659 56,376 232,722 215,558
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130,234 119,125 492,385 450,789
----------------------------------------------------------------------------
Income before taxes 32,800 64,211 217,652 276,055
Income taxes (reductions) (30,831) (3,424) (535) (25,215)
----------------------------------------------------------------------------
Net income 63,631 67,635 218,187 301,270
Changes in comprehensive income,
net of taxes (2,512) - (5,994) -
----------------------------------------------------------------------------
Comprehensive income 61,119 67,635 212,193 301,270
----------------------------------------------------------------------------
Accumulated earnings, beginning
of period 138,708 223,078 214,417 237,163
Distributions declared (77,136) (76,296) (307,401) (324,016)
----------------------------------------------------------------------------
Accumulated earnings, end of
period $ 125,203 $ 214,417 $ 125,203 $ 214,417
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - basic $ 0.60 $ 0.65 $ 2.07 $ 2.95
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income per unit - diluted $ 0.59 $ 0.65 $ 2.06 $ 2.90
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----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.



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----------------------------------------------------------------------------
Consolidated Statements of Cash Flows

(thousands) Three Months end Years ended
December 31, December 31,
2007 2006 2007 2006
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(unaudited)

Cash provided by (used in):

Operating Activities:
Net income $ 63,631 $ 67,635 $ 218,187 $ 301,270
Items not requiring cash from
operations:
Depreciation, depletion and
accretion 60,659 56,376 232,722 215,558
Unit-based compensation 2,809 714 7,351 4,890
Unrealized gains (losses) on
financial instruments 31,510 (3,420) 45,058 -
Future income taxes
(reductions) (30,831) - (535) (25,280)
Asset retirement expenditures (4,784) (2,862) (8,338) (5,694)
Changes in non-cash working
capital items (27,535) (23,987) (21,424) (15,694)
----------------------------------------------------------------------------

95,459 94,456 473,021 475,050
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financing Activities:
Issuance of equity, net of
issue costs 964 1,096 8,144 5,936
Distributions (77,079) (78,763) (307,125) (325,064)
Changes in long-term debt 43,704 45,276 200,331 168,521
Changes in non-cash working
capital items (405) (276) (164) 121
----------------------------------------------------------------------------

(32,816) (32,667) (98,814) (150,486)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investing Activities:
Exploitation and development (58,440) (58,744) (267,660) (280,563)
Business acquisitions - - - (25,800)
Property acquisitions (1,585) 87 (100,806) (10,355)
Property dispositions 2,010 258 2,110 365
Changes in non-cash working
capital items (4,628) (3,390) (7,851) (8,211)
----------------------------------------------------------------------------

(62,643) (61,789) (374,207) (324,564)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Change in cash - - - -

Cash, beginning of period - - - -
----------------------------------------------------------------------------

Cash, end of period $ - $ - $ - $ -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

See accompanying notes to the consolidated financial statements.


BONAVISTA ENERGY TRUST

Notes to Consolidated Financial Statements

For the year ended December 31, 2007 (unaudited)

Structure of the Trust and Basis of Presentation:

Bonavista Energy Trust ("Bonavista" or the "Trust") 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 6) 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.

1. Changes in accounting policy:

Financial Instruments and Hedging Activities

Effective January 1, 2007, Bonavista adopted the Canadian Institute of Chartered Accountants ("CICA") Section 3855, "Financial Instruments - Recognition and Measurement", Section 3865, "Hedges", Section 1530, "Comprehensive Income", and Section 3861, "Financial Instruments - Disclosure and Presentation". Bonavista has adopted these standards prospectively and the comparative interim consolidated financial statements have not been restated. Transition amounts have been recorded in accumulated other comprehensive income.

As at January 1, 2007, the following adjustments were made to the consolidated balance sheet on adoption of the new standards:



----------------------------------------------------------------------------
January 1, 2007
----------------------------------------------------------------------------
(thousands)

Accounts receivable - financial instruments $ 8,563
Future income taxes (2,569)
Accumulated other comprehensive income (5,994)
----------------------------------------------------------------------------


(a) Financial instruments - recognition and measurement

This new standard requires all financial instruments within its scope, including all derivatives, to be recognized on the balance sheet initially at fair value. Subsequent measurement of all financial assets and liabilities except those held-for-trading and available for sale are measured at amortized cost determined using the effective interest rate method. Held-for-trading financial assets are measured at fair value with changes in fair value recognized in earnings. Available-for-sale financial assets are measured at fair value with changes in fair value recognized in comprehensive income and reclassified to earnings when derecognized or impaired.

Additional disclosure requirements for financial instruments have been approved by the CICA, and will be required disclosure for Bonavista beginning January 1, 2008.

(b) Derivatives

Bonavista continues to utilize financial derivatives and non-financial derivatives, such as commodity sales contracts requiring physical delivery, to manage the price risk attributable to anticipated sale of oil and natural gas production. Bonavista has elected to account for its commodity sales contracts which were entered into and continue to be held for the purpose of receipt or delivery of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts on an accrual basis rather than as non-financial derivatives. Prior to adoption of the new standards, physical receipt and delivery contracts did not fall within the scope of the definition of a financial instrument and were also accounted for as executory contracts.

Prior to January 1, 2007, Bonavista applied hedge accounting to its forward sales contracts. On January 1, 2007, Bonavista discontinued hedge accounting for all existing financial derivatives. Net derivative gains in accumulated other comprehensive income at January 1, 2007 was reclassified to income in future periods as the original hedged transactions affect net income. From that date forward, the changes in fair value of such derivatives have been recognized in net income when incurred. Discontinuing hedge accounting did not affect the Trust's reported cash flows.

(c) Embedded derivatives

On adoption, Bonavista elected to recognize, as separate assets and liabilities, only for those embedded derivatives in hybrid instruments issued, acquired or substantively modified after January 1, 2003. Bonavista did not identify any material embedded derivatives, which required separate recognition and measurement.

(d) Other comprehensive income

The new standards require a new statement of comprehensive income, which is comprised of net income and other comprehensive income, which, for Bonavista, relates to changes in gains or losses on derivatives designated as cash flow hedges. Bonavista has prepared a statement showing the changes in the accumulated other comprehensive income.

On December 1, 2006 the CICA issued three new accounting standards, Section 1535, "Capital Disclosures", Section 3862, "Financial Instruments - Disclosures" and Section 3863, "Financial Instruments - Presentation". These three new standards will require additional disclosure in the Trust's financial statements commencing January 1, 2008. The Trust will be required to adopt Section 3064 "Goodwill and Intangible Assets" on January 1, 2009. Canada's Accounting Standards Board confirmed January 1, 2011 as the effective date for complete convergence of Canadian GAAP to International Financial Reporting Standards ("IFRS"). The Trust will continue to monitor and assess the impact of the planned convergence of Canadian GAAP with IFRS.

2. Business relationships:

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 Plan of Arrangement, Bonavista entered into a Technical Services Agreement ("TSA") with NuVista, whereby, Bonavista received payment for certain technical and administrative services provided by it to NuVista on a cost recovery basis. Effective January 1, 2007 the terms of the TSA were amended to reflect the reduced level of services provided by Bonavista and subsequently on August 31, 2007 the TSA was terminated and replaced with a new services agreement that reflects the remaining ongoing services that will be provided by Bonavista.

For the year ended December 31, 2007 NuVista paid Bonavista $1.4 million (2006 - $2.3 million) in fees relating to general and administrative services provided to NuVista, in addition NuVista charged Bonavista management fees for a jointly owned partnership totaling $1.4 million (2006 - nil). Bonavista also charged NuVista $975,000 (2006 - nil) for costs that are outside the TSA relating to NuVista's share of direct charges from third parties. As at December 31, 2007, the amount receivable from NuVista was $703,000 (2006 - $2.7 million).

3. 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. For the year ended December 31, 2007 the Trust has changed its estimated costs to reclaim and abandon the wells and facilities and the estimated timing of the costs to be incurred in future periods, resulting in an increase of $16.0 million (2006 - nil). The Trust estimates the total undiscounted amount of expenditures required to settle its asset retirement obligations is approximately $540.9 million (2006 - $475.2 million) which will be incurred over the next 51 years. The majority of the costs will be incurred between 2010 and 2037. A credit-adjusted risk-free rate of 7.5% (2006 - 7.5%) and an inflation rate of 2% (2006 - 2%) were 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,
2007 2006
--------------------------------------------------------
(thousands)

Balance, beginning of year $ 96,324 $ 82,819

Accretion expense 7,333 6,279
Liabilities incurred 1,629 11,332
Liabilities acquired 3,976 1,588
Liabilities settled (8,338) (5,694)
Changes in assumptions 15,969 -
--------------------------------------------------------

Balance, end of year $ 116,893 $ 96,324
--------------------------------------------------------
--------------------------------------------------------


4. Long-term debt:

The Trust has a $1.0 billion 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, 2010.

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.

Financing expenses for the year ended December 31, 2007 include interest on bank loans of $31.6 million (2006 - $22.4 million) and convertible debentures of $3.6 million (2006 - $4.5 million). For the three months ended December 31, 2007, Bonavista paid cash interest of $11.3 million (2006 - $8.0 million).

5. 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 included in Unitholders' equity at the date of issue was $4.7 million. The issue costs are amortized to net income 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, 2007:



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Debt Equity
Component Component
---------------------------------------------------------------------------
(thousands)

Balance, December 31, 2006 $ 51,170 $ 1,117
Accretion 75 -
Issue expenses related to conversions to trust units 29 -
Amortization of issue expenses 702 -
Conversion to trust units (3,146) (63)
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Balance, December 31, 2007 $ 48,830 $ 1,054
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---------------------------------------------------------------------------


6. Unitholders' equity:

a) Authorized:

Unlimited number of voting trust units.

b) Issued and outstanding:

(i) Trust units:



----------------------------------------------------------------------------
Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2006 84,839 $ 834,625
Issued on conversion of convertible debentures 125 3,146
Issued on conversion of exchangeable shares 110 411
Issued upon exercise of trust unit incentive rights 683 8,144
Issue costs, related to debenture conversions - (29)
Adjustment to equity component of debenture on
conversion - 63
Unit-based compensation - 4,271
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Balance, December 31, 2007 85,757 $ 850,631
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----------------------------------------------------------------------------


(ii) Contributed surplus:



----------------------------------------------------------------------------
Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2006 $ 4,973
Unit-based compensation expense 7,351
Unit-based compensation capitalized 1,316
Exercise of trust unit incentive rights (4,271)
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Balance, December 31, 2007 $ 9,369
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(iii) Exchangeable shares:



----------------------------------------------------------------------------

Number Amount
----------------------------------------------------------------------------
(thousands)
Balance, December 31, 2006 12,297 $ 75,121
Exchanged for trust units (67) (411)
----------------------------------------------------------------------------

Balance, December 31, 2007 12,230 $ 74,710
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Exchange ratio, December 31, 2007 1.72244 -
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Trust units issuable on exchange 21,066 $ 74,710
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c) Trust unit incentive rights plan:

For the three months ended December 31, 2007 there were 45,400 trust unit incentive rights issued with an average exercise price of $29.10 per trust unit and an estimated fair value of $8.55 per trust unit. As at December 31, 2007 there were 3,726,125 trust unit rights outstanding with an average exercise price of $24.76 per trust unit. 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%; volatility of 34%; a forfeiture rate of 10% and an expected life of 4.5 years.

d) Restricted trust unit incentive plan:

The Trust has a Restricted Trust Unit Incentive Plan that allows the Trust to award trust units to directors, officers, employees and service providers. The number of restricted trust units available under the plan shall be limited to 5% of the aggregate number of issued and outstanding units of the Trust. Vesting arrangements are within the discretion of our board of directors, but all awards will vest within three years from the date of grant. On the vesting date the holder will receive either: (i) one trust unit; or (ii) the cash equivalent of one trust unit for each unit award as well as all distributions made on trust units from the date of grant to and including the vesting date. Trust units may be issued from treasury or purchased on the open market.

The following table summarizes the restricted trust unit's outstanding under the plan at December 31, 2007:



------------------------------------------
Balance, December 31, 2006 -
Granted 168,844
Forfeited (9,105)
------------------------------------------

Balance, December 31, 2007 159,739
------------------------------------------
------------------------------------------


e) Per unit amounts:

The following table summarizes the weighted average trust units, exchangeable shares and convertible debentures used in calculating net income per trust unit:



----------------------------------------------------------------------
Three months
ended
December 31, 2007
----------------------------------------------------------------------
(thousands)
Trust units 85,677
Exchangeable shares converted at the exchange ratio 21,085
----------------------------------------------------------------------
Basic equivalent trust units 106,762
Convertible debentures 1,845
Trust unit incentive rights 495
----------------------------------------------------------------------
Diluted equivalent trust units 109,102
----------------------------------------------------------------------
----------------------------------------------------------------------


For the purposes of calculating net income per trust unit on a diluted basis, the net income has been increased by $1.1 million (2006 - $1.1 million) with respect to the accretion, amortization and interest expense on the convertible debentures.

f) Accumulated other comprehensive income:

The following table summarizes the amounts recognized on adoption of the new accounting standards for financial instruments and also the amortization of the amount recognized in accumulated other income on January 1, 2007:



----------------------------------------------------------------------------
(thousands)
Balance, January 1, 2007 $ -
Transition adjustment for discontinuance of hedge accounting,
net of taxes of $2,569 5,994
Reclassification to net income during the year, net of taxes
of $2,569 (5,994)
----------------------------------------------------------------------------

Balance, December 31, 2007 $ -
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----------------------------------------------------------------------------


7. Income taxes:

As a result of the recent changes to income trust tax legislation modifying the taxation of certain flow through entities including mutual fund trusts and their unitholders, a non-cash provision for future income taxes of $36.4 million was recorded for the year ended December 31, 2007, resulting from the book basis of the assets and liabilities in the Trust and its subsidiary trust, exceeding their tax basis. These changes apply a tax at the trust level on distributions of certain income at a rate of tax comparable to the combined federal and provincial corporate tax rate. The distribution tax will only apply in respect of distributions of income and will not apply to returns of capital. It is expected that Bonavista will not be subject to the recent tax changes until January 1, 2011. Previously, future income taxes were recorded only on the temporary differences in the corporate subsidiaries of the Trust.

8. Financial instrument activities:

a) Balance sheet financial instruments:

Bonavista's financial instruments recognized in the Consolidated Balance Sheet consist of accounts receivable, accounts payable, long-term debt, and other long-term obligations. The market deficit of the Trust's derivative financial instruments is $45.1 million. Unless otherwise noted, carrying values reflect the current fair value of the Trust's financial instruments. The estimated fair values of recognized financial instruments have been determined based on Bonavista's assessment of available market information and appropriate methodologies, or through comparisons to similar instruments. The fair market value of the convertible debentures as at December 31, 2007 is $52.5 million.

b) Commodity price contracts:

i) Financial instruments:

As at December 31, 2007, 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
----------------------------------------------------------------
5,000 gjs/d CDN$ 7.50 - January 1, 2008 -
CDN$ 10.55 - AECO March 31, 2008
5,000 gjs/d CDN$ 7.00 - April 1, 2008 -
CDN$ 9.00 - AECO October 31, 2008
7,000 bbls/d US$ 65.43 - January 1, 2008 -
US$ 78.58 - WTI December 31, 2008
1,000 bbls/d CDN$ 49.00 - January 1, 2008 -
CDN$ 57.00 - Bow River December 31, 2008
2,000 bbls/d US$ 65.00 - January 1, 2009 -
US$ 80.50 - WTI March 31, 2009
----------------------------------------------------------------


As at December 31, 2007, the market deficit of these derivative financial instruments was approximately $45.1 million.

ii) Physical purchase contracts:

As at December 31, 2007, the Trust has entered into direct sale costless collars to sell natural gas as follows:



---------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
---------------------------------------------------------------------------
20,000 gjs/d $ 7.75 - $ 10.53 January 1, 2008 - March 31, 2008
---------------------------------------------------------------------------


9. Subsequent events:

a) Property acquisition:

On January 14, 2008, the Trust completed the acquisition of producing and undeveloped oil and natural gas properties in the Willesden Green area of our South Central Alberta core region and the Fireweed area located in our Northeast British Columbia core region for a net purchase price of $167 million.

b) Financial instrument activities:

Subsequent to December 31, 2007, the Trust has entered into the following commodity contracts:

i) Financial instruments:

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
----------------------------------------------------------------
20,000 gjs/d CDN$ 7.38 - April 1, 2008 -
CDN$ 8.46 - AECO October 31, 2008
2,000 bbls/d CDN$ 61.00 - April 1, 2008 -
CDN$ 71.75 - Bow River December 31, 2008
1,000 bbls/d US$ 85.00 - January 1, 2009 -
US$ 105.60 - WTI December 31, 2009
----------------------------------------------------------------


ii) Physical purchase contracts:

The Trust has entered into direct sale costless collars to sell natural gas as follows:



---------------------------------------------------------------------------
Volume Average Price (CDN$ - AECO) Term
---------------------------------------------------------------------------
45,000 gjs/d $ 7.19 - $ 8.36 April 1, 2008 - October 31, 2008
25,000 gjs/d $ 7.65 - $ 9.65 November 1, 2008 - March 31, 2009
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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) 213-4315
    or
    Ronald J. Poelzer
    Executive Vice President & CFO
    (403) 213-4308
    or
    Bonavista Petroleum Ltd.
    700, 311 - 6th Avenue SW
    Calgary, AB T2P 3H2
    (403) 213-4300
    Website: www.bonavistaenergy.com